scholarly journals Experimental Study on the Effect of ASP Flooding on Improving Oil Recovery in Low Permeability Reservoirs Based on a Partial Quality Tool

Processes ◽  
2020 ◽  
Vol 8 (3) ◽  
pp. 296 ◽  
Author(s):  
Bin Huang ◽  
Xinyu Hu ◽  
Cheng Fu ◽  
Quan Zhou
Keyword(s):  
Molecular Weight ◽  
High Molecular Weight ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Low Permeability ◽  
Displacement Effect ◽  
Oil Displacement ◽  
Matching Degree ◽  
Low Permeability Reservoirs ◽  
Quality Tool

In order to solve the problem of the poor oil displacement effect of high molecular weight alkali/surfactant/polymer (ASP) solution in low permeability reservoirs, Daqing Oilfield uses a partial quality tool to improve the oil displacement effect in low permeability reservoirs. In the formation, the partial quality tool degrades the polymer through active shearing action, reducing the molecular weight of the polymer, to improve the matching degree to the low permeability oil layer and the oil recovery. In order to study the ability of the partial quality tool to improve the oil displacement effect, the matching degree of high molecular weight ASP solution to low permeability cores is studied, and the ability of quality control tools to change the molecular weight is studied. Then, experimental research on the pressure and oil displacement effect of high molecular weight ASP solution before and after the actions of the partial quality tool is carried out. The results show that ASP solutions with molecular weights of 1900 × 104 and 2500 × 104 have a poor oil displacement effect in low permeability reservoirs. After the action of the partial quality tool, the injection pressure is reduced by 5.22 MPa, and the oil recovery is increased by 7.79%. The injection pressure of the ASP solution after shearing by the partial quality tool is lower than that of the ASP solution with the same molecular weight and concentration without shearing, but the oil recovery is lower. On the whole, the use of the partial quality tool can obviously improve the oil displacement effect in low permeability reservoirs.

The Research and Evaluation of Finely Layered Water Injection Standard in Low-Permeability Reservoirs - A Case from Block A in one Low-Permeability Reservoir

2014 ◽  
Vol 1073-1076 ◽  
pp. 2310-2315 ◽  
Author(s):  
Ming Xian Wang ◽  
Wan Jing Luo ◽  
Jie Ding
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Low Permeability ◽  
Reservoir Permeability ◽  
Engineering Parameters ◽  
The Common ◽  
Common Problems ◽  
Low Permeability Reservoirs

Due to the common problems of waterflood in low-permeability reservoirs, the reasearch of finely layered water injection is carried out. This paper established the finely layered water injection standard in low-permeability reservoirs and analysed the sensitivity of engineering parameters as well as evaluated the effect of the finely layered water injection standard in Block A with the semi-quantitative to quantitative method. The results show that: according to the finely layered water injection standard, it can be divided into three types: layered water injection between the layers, layered water injection in inner layer, layered water injection between fracture segment and no-fracture segment. Under the guidance of the standard, it sloved the problem of uneven absorption profile in Block A in some degree and could improve the oil recovery by 3.5%. The sensitivity analysis shows that good performance of finely layered water injection in Block A requires the reservoir permeability ratio should be less than 10, the perforation thickness should not exceed 10 m, the amount of layered injection layers should be less than 3, the surface injection pressure should be below 14 MPa and the injection rate shuold be controlled at about 35 m3/d.

scholarly journals Experimental Research on the Optimization and Evaluation of the Polymer/Chromium-Ion Deep Profile Control System for the Fractured Low-Permeability Reservoirs

Processes ◽  
2020 ◽  
Vol 8 (9) ◽  
pp. 1021
Author(s):  
Daiyin Yin ◽  
Shuang Song ◽  
Qi Xu ◽  
Kai Liu
Keyword(s):  
Molecular Weight ◽  
Control System ◽  
High Molecular Weight ◽  
Low Molecular Weight ◽  
Low Permeability ◽  
Chromium Ion ◽  
Oil Displacement ◽  
Profile Control ◽  
Deep Profile ◽  
Plugging Performance

The matrix/fracture conductivity of a fractured low-permeability reservoir is variable, and its heterogeneity is serious. When carrying out deep profile control measures, it is difficult to inject under the premise of ensuring the plugging effect. According to the characteristics of the fractured low-permeability reservoir in Chaoyanggou Oilfield, the polymer/chromium ion deep profile control system was optimized via a viscosity evaluation experiment, liquidity experiment and oil displacement experiment. The experimental results show that the high molecular weight main agent/low concentration system and low molecular weight main agent/high concentration system can meet the gel strength requirement. The evaluation results of the injection ability and plugging performance of the fractured low-permeability core show that a high molecular weight profile control system is difficult to inject, while a low molecular weight profile control system has a poor plugging performance and high cost after simulated shear. Therefore, the formulation of the profile control system was determined to be a polymer with a molecular weight of 16 million g·mol−1 as the main agent with a concentration of 1000–1500 mg·L−1. As assisting agents, the concentrations of thiourea, NaCl and NaHCO3 were 900 mg·L−1, 800 mg·L−1 and 700 mg·L−1, respectively. The plugging rate of the system was 87.6%, and the resistance coefficient was 19.2. Finally, a fractured low-permeability core model with parallel long cores was designed, and the optimal profile control system was used for the core oil-displacement experiment. Compared with the water-flooding experiment, the plugging rate can be increased by 6.9–8.0%.

scholarly journals Improving Oil Recovery of the Heterogeneous Low Permeability Reservoirs by Combination of Polymer Hydrolysis Polyacrylamide and Two Highly Biosurfactant-Producing Bacteria

2021 ◽  
Vol 14 (1) ◽  
pp. 423
Author(s):  
Shuwen Xue ◽  
Yanhong Zhao ◽  
Chunling Zhou ◽  
Guangming Zhang ◽  
Fulin Chen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Low Permeability ◽  
Bacterial Fermentation ◽  
The Core ◽  
Oil Displacement ◽  
Polymer Hydrolysis ◽  
Enhance Oil Recovery ◽  
Low Permeability Reservoirs ◽  
Microbial Flooding ◽  
Poly Acrylamide

Polymer hydrolysis polyacrylamide and microbes have been used to enhance oil recovery in many oil reservoirs. However, the application of this two-method combination was less investigated, especially in low permeability reservoirs. In this work, two bacteria, a rhamnolipid-producing Pseudomonas aeruginosa 8D and a lipopeptide-producing Bacillus subtilis S4, were used together with hydrolysis poly-acrylamide in a low permeability heterogeneous core physical model. The results showed that when the two bacterial fermentation liquids were used at a ratio by volumeof 1:3 (v:v), the mixture showed the optimal physicochemical properties for oil-displacement. In addition, the mixture was stable under the conditions of various temperature (20–70 °C) and salinity (0–22%). When the polymer and bacteria were mixed together, it had no significant effects in the viscosity of polymer hydrolysis polyacrylamide and the viability of bacteria. The core oil-displacement test displayed that polymer hydrolysis polyacrylamide addition followed by the bacterial mixture injection could significantly enhance oil recovery. The recovery rate was increased by 15.01% and 10.03%, respectively, compared with the sole polymer hydrolysis polyacrylamide flooding and microbial flooding. Taken together, these results suggest that the strategy of polymer hydrolysis poly-acrylamide addition followed by microbial flooding is beneficial for improving oil recovery in heterogeneous low permeability reservoirs.

Lab Studies of MEOR Strains Optimization for High Salinity Reservoirs

2011 ◽  
Vol 343-344 ◽  
pp. 844-848
Author(s):  
Jing Chun Wu ◽  
Xiao Ming Lv ◽  
Zhi Jie Ou ◽  
Dai Yin Yin
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Produced Water ◽  
High Salinity ◽  
Low Permeability ◽  
Displacement Effect ◽  
Physical Experiments ◽  
Fermentation Liquor ◽  
Laboratory Results ◽  
Low Permeability Reservoirs

.Aiming at the high salinity at low-permeability reservoirs, a strain named S-4 that can yield a kind of bio-surfactants was screened from the produced water of oil wells in use of the Hemolysis of the bio-surfactants and its characteristics of making the color of blue gel plate change in its formation process. The laboratory results show that the surface tension of the strains fermentation liquor becomes less than 30mN/m after cultured by crude oil as the carbon source, and it would remain at the value of 31mN/m even if the concentration becomes a half; this bio-surfactant keeps stable when the salinity is in the range of 4000mg/L～50000mg/L; In physical experiments the strains can improve crude oil recovery ratio by 4% which shows a good oil displacement effect.

Evaluation of New Active Polymer Systems

2013 ◽  
Vol 848 ◽  
pp. 7-10
Author(s):  
Jia Bin Tang ◽  
Wen Xiang Wu ◽  
Zhu Xin Zhang
Keyword(s):  
Interfacial Tension ◽  
Polymer Solution ◽  
Simulation Experiment ◽  
Physical Simulation ◽  
Low Permeability ◽  
Displacement Effect ◽  
Polymer Systems ◽  
Oil Displacement ◽  
Low Permeability Reservoirs ◽  
Better Than

Using the physical simulation experiment, for the new active polymers, common carve and polymer 25 million to act on interfacial tension test, the results indicate, interfacial tension for common carve and polymer 25 million is about 10 mn/m. and interfacial tension for the active polymer is about 1 mn/m. Rheology showed that the viscosity and elasticity of active polymer solution were higher than 25 million polymer.In liquidity experiment, active polymer solution has the better liquidity than in 25 million polymers in the low permeable formation,the flooding effect of active polymer is better than 25 million polymer and common carve polymer.the better injection and better oil displacement features of active polymer are suitable for low permeability reservoirs to improve oil displacement effect.

Experimental Investigation of Polyethylene Oxide Polymer Solutions for Enhanced Oil Recovery in Low-Permeability Carbonate Rocks

SPE Journal ◽  
2021 ◽  
pp. 1-16
Author(s):  
Miguel Mejía ◽  
Gary A. Pope ◽  
Haofeng Song ◽  
Matthew T. Balhoff
Keyword(s):  
Molecular Weight ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Polyethylene Oxide ◽  
Carbonate Rocks ◽  
Sodium Acrylate ◽  
Low Permeability ◽  
Improved Oil Recovery ◽  
Low Permeability Reservoirs ◽  
First Time

Summary New experiments using polyethylene oxide (PEO) polymer were performed to evaluate its potential for enhanced oil recovery (EOR) applications in low-permeability reservoirs. This is the first time that high molecular weight PEO solutions have been shown to have favorable transport in low-permeability (~20 md) carbonate cores and the first time PEO has been shown to improve oil recovery in a fractured carbonate core. Rheology measurements in synthetic seawater show the higher viscosity of PEO solutions compares favorably to the viscosity of acrylamide–sodium acrylate (AM-AA) copolymers of similar molecular weight because PEO is less sensitive to hardness and high salinity. Filtration experiments using 0.45 μm cellulose filters show very favorable filtration ratios of PEO with a molecular weight of 4 million g/mol, which is consistent with its favorable transport in low-permeability cores. Four coreflood experiments in Texas Cream Limestone (TC Limestone) cores demonstrate the viability of PEO for EOR in low-permeability carbonate rocks. Single-phase experiments show 4 million g/mol PEO solutions transported through 18 and 28 md TC Limestone cores. Oil recovery experiments show 4 million g/mol PEO solutions transported and was more efficient than waterflooding in aged TC Limestone with favorable retention of 40 µg/g rock. An oil recovery experiment in an artificially fractured TC Limestone core improved oil recovery by a remarkable 15% considering the very large fracture-matrix permeability contrast (>7,000). These experimental results as well as other favorable properties of PEO reported in the literature indicate PEO should be considered for some EOR applications, especially in low-permeability reservoirs.

ASSESSMENT OF OIL WELL PRODUCTIVITY IN LOW-PERMEABILITY RESERVOIRS IN THE FIELDS OF EASTERN SIBERIA

2017 ◽  
pp. 30-36
Author(s):  
R. V. Urvantsev ◽  
S. E. Cheban
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Oil And Gas ◽  
Oil Extraction ◽  
Low Permeability ◽  
Oil Well ◽  
Eastern Siberia ◽  
Development Costs ◽  
Traditional Fields ◽  
Low Permeability Reservoirs

The 21st century witnessed the development of the oil extraction industry in Russia due to the intensifica- tion of its production at the existing traditional fields of Western Siberia, the Volga region and other oil-extracting regions, and due discovering new oil and gas provinces. At that time the path to the development of fields in Eastern Siberia was already paved. The large-scale discoveries of a number of fields made here in the 70s-80s of the 20th century are only being developed now. The process of development itself is rather slow in view of a number of reasons. Create a problem of high cost value of oil extraction in the region. One of the major tasks is obtaining the maximum oil recovery factor while reducing the development costs. The carbonate layer lying within the Katangsky suite is low-permeability, and its inventories are categorised as hard to recover. Now, the object is at a stage of trial development,which foregrounds researches on selecting the effective methods of oil extraction.

scholarly journals Study Rheological Behavior of Polymer Solution in Different-Medium-Injection-Tools

Polymers ◽  
2019 ◽  
Vol 11 (2) ◽  
pp. 319 ◽  
Author(s):  
Bin Huang ◽  
Xiaohui Li ◽  
Cheng Fu ◽  
Ying Wang ◽  
Haoran Cheng
Keyword(s):  
Molecular Weight ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Injection Rate ◽  
Injection Velocity ◽  
Structural Parameter ◽  
Local Perturbation ◽  
Polymer Injection ◽  
Single Pipe

Previous studies showed the difficulty during polymer flooding and the low producing degree for the low permeability layer. To solve the problem, Daqing, the first oil company, puts forward the polymer-separate-layer-injection-technology which separates mass and pressure in a single pipe. This technology mainly increases the control range of injection pressure of fluid by using the annular de-pressure tool, and reasonably distributes the molecular weight of the polymer injected into the thin and poor layers through the shearing of the different-medium-injection-tools. This occurs, in order to take advantage of the shearing thinning property of polymer solution and avoid the energy loss caused by the turbulent flow of polymer solution due to excessive injection rate in different injection tools. Combining rheological property of polymer and local perturbation theory, a rheological model of polymer solution in different-medium-injection-tools is derived and the maximum injection velocity is determined. The ranges of polymer viscosity in different injection tools are mainly determined by the structures of the different injection tools. However, the value of polymer viscosity is mainly determined by the concentration of polymer solution. So, the relation between the molecular weight of polymer and the permeability of layers should be firstly determined, and then the structural parameter combination of the different-medium-injection-tool should be optimized. The results of the study are important for regulating polymer injection parameters in the oilfield which enhances the oil recovery with reduced the cost.

Development of the Surfactant-Based Chemical EOR Formula for Low Permeability Reservoirs

2021 ◽  
Author(s):  
Nancy Chun Zhou ◽  
Meng Lu ◽  
Fuchen Liu ◽  
Wenhong Li ◽  
Jianshen Li ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Aqueous Solubility ◽  
Low Permeability ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Key Factors ◽  
Low Salinity ◽  
Low Tension ◽  
Low Permeability Reservoirs

Abstract Based on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding. Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions. Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs. In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.

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