scholarly journals Development and Performance Evaluation of Steam Channeling Plugging Agent of Thermal Oil Recovery

2015 ◽  
Vol 8 (1) ◽  
pp. 58-63
Author(s):  
Wang Chunsheng ◽  
Sun Yingfan ◽  
He Chenglin ◽  
Zhang Haipeng ◽  
Du Qiuying
Keyword(s):  
Thermal Stability ◽  
High Temperature ◽  
Oil Recovery ◽  
Ph Value ◽  
Control Agent ◽  
Formation Condition ◽  
Cross Linking ◽  
Profile Control ◽  
High Efficient ◽  
And Performance

Under the constraints of high temperature and heterogeneity, the common profile control agent can not effectively plug the steam channeling. To address this issue, it is necessary to develop the high temperature resistance steam channeling plugging agent to improve the steam suction profile in the heavy oil reservoir. This paper used Simple Variable Method to optimize the content of the components of the high temperature resistant plugging agent. Static performances evaluation aims to study the influence rules of the formation condition (temperature, salinity and pH value). Dynamic evaluation is used to study its performance (plugging ratio, residual resistance factor, scouring resistance and thermal stability) in the sand-filled pipe to testify its applicability. The ratio of the component and the injection sequence are shown as follows: 0.03% coagulant +2.2% cross-linking agent I + 1.2% cross-linking II + 6% high efficient main agent. The evaluation experiment results show that the gel can resist at least 280ºC, the plugging ratio is above 93.1%. The plugging ratio only have a 8.43% reduction after scoured by 15 PV steam (280ºC). After a 10-day thermal stability experiment (280 ºC), the plugging ratio is still above 80%. The result indicated that the plugging agent is suitable for the improvement of steam suction profile. The suggested way of injection is also provided.

Water-Flooding Fluid Diversion Copolymeric Microsphere Prepared by Inverse Suspension Polymerization

e-Polymers ◽  
2007 ◽  
Vol 7 (1) ◽  
Author(s):  
Huang Zhiyu ◽  
Lu Hongsheng ◽  
Zhang Tailiang
Keyword(s):  
Thermal Stability ◽  
High Temperature ◽  
Oil Recovery ◽  
High Salinity ◽  
Suspension Polymerization ◽  
Oil Reservoirs ◽  
Water Flooding ◽  
Toughness Index ◽  
Inverse Suspension Polymerization ◽  
Enhance Oil Recovery

Abstract In order to enhance oil recovery in high-temperature and high-salinity oil reservoirs, the copolymeric microspheres containing acrylamide (AM), acrylonitrile (AN) and AMPS was synthesized by inverse suspension polymerization. The copolymeric microsphere was very uniform and the size could be changed according to the condition of polymerization. The lab-scale studies showed that the copolymeric microsphere exhibit good salt-tolerance and thermal-stability when immersed in 20×105 mg/L NaCl(or KCl) solution, 7500 mg/L CaCl2 (or MgCl2) solution or 2000 mg/L FeCl3 solution, respectively. The copolymeric microsphere showed satisfactory absorbency rates. The sand-pipes experiments confirmed that the average toughness index was 1.059. It could enhance the oil recovery by about 3% compared with the corresponding irregular copolymeric particle.

scholarly journals Role of Ionic Headgroups on the Thermal, Rheological, and Foaming Properties of Novel Betaine-Based Polyoxyethylene Zwitterionic Surfactants for Enhanced Oil Recovery

Processes ◽  
2019 ◽  
Vol 7 (12) ◽  
pp. 908 ◽  
Author(s):  
Muhammad Shahzad Kamal ◽  
Syed Muhammad Shakil Hussain ◽  
Lionel Talley Fogang
Keyword(s):  
Thermal Stability ◽  
High Temperature ◽  
Oil Recovery ◽  
Structural Changes ◽  
Foam Stability ◽  
Foaming Properties ◽  
Zwitterionic Surfactants ◽  
Reservoir Conditions ◽  
Thermal Stability Of

Long-term thermal stability of surfactants under harsh reservoir conditions is one of the main challenges for surfactant injection. Most of the commercially available surfactants thermally degrade or precipitate when exposed to high-temperature and high-salinity conditions. In this work, we designed and synthesized three novel betaine-based polyoxyethylene zwitterionic surfactants containing different head groups (carboxybetaine, sulfobetaine, and hydroxysulfobetaine) and bearing an unsaturated tail. The impact of the surfactant head group on the long-term thermal stability, foam stability, and surfactant–polymer interactions were examined. The thermal stability of the surfactants was assessed by monitoring the structural changes when exposed at high temperature (90 °C) for three months using 1H-NMR, 13C-NMR, and FTIR analysis. All surfactants were found thermally stable regardless of the headgroup and no structural changes were evidenced. The surfactant–polymer interactions were dominant in deionized water. However, in seawater, the surfactant addition had no effect on the rheological properties. Similarly, changing the headgroup of polyoxyethylene zwitterionic surfactants had no major effect on the foamability and foam stability. The findings of the present study reveal that the betaine-based polyoxyethylene zwitterionic surfactant can be a good choice for enhanced oil recovery application and the nature of the headgroup has no major impact on the thermal, rheological, and foaming properties of the surfactant in typical harsh reservoir conditions (high salinity, high temperature).

Experimental Research on Profile Control Technology Using Sewage Flowed Back from Injecting-Polymer Wells

2012 ◽  
Vol 550-553 ◽  
pp. 2112-2116
Author(s):  
Zhi Feng Cai ◽  
Guang Sheng Cao ◽  
Shao Wei Cheng
Keyword(s):  
Experimental Research ◽  
Oil Recovery ◽  
Economic Benefits ◽  
Gelling Agent ◽  
Cross Linking ◽  
Control Technology ◽  
Use Of Resources ◽  
Profile Control ◽  
Ph Modifier ◽  
Gelling Time

With the amount of injecting-polymer wells in Xingnan SS block of Daqing Oilfield increasing gradually, a lot of problems, such as the treatment and use of sewage flowed back from injecting-polymer wells, need to be solved. The concentrations of gelling agent, cross-linking agent, and regulators have been optimized by measuring gelling strength and gelling time. The additives about pH modifier and deoxidizer have been selected. As a result, the formula system of profile control using sewage flowed back from injecting-polymer wells has been formed, realizing reuse of sewage, reaching the goal of improving oil recovery. The research in this paper not only solves the problem of re-injecting sewage flowed back from injecting-polymer wells, making full use of resources, but saves costs, improving economic benefits.

Preparation and Application of J-F Profile Control Agent

2014 ◽  
Vol 962-965 ◽  
pp. 727-730
Author(s):  
Zhan Shuang Xu
Keyword(s):  
Ph Value ◽  
Injection Pressure ◽  
Binary Compound ◽  
Salt Resistance ◽  
Temperature Tolerance ◽  
Economic Benefits ◽  
Control Agent ◽  
Utilization Rate ◽  
Profile Control ◽  
Liaohe Oilfield

In Liaohe oilfield Xing 28 block before and during the alkali/polymer binary compound flooding process, there are heterogeneity contradictions on vertical and plane formation. In order to solve this contradiction, improve the utilization rate of oil displacement agent, J - F profile control agent was developed successfully, the profile control agent is not restricted by formation pH value and gel time, of good resistance to flushing, temperature tolerance and salt resistance. Through the field test, using J-F profile control agent the injection profile changed significantly and the injection pressure increased, a remarkable economic benefits and social benefits are gained.

A New High-Temperature Gel for Profile Control in Heavy Oil Reservoirs

2015 ◽  
Vol 138 (2) ◽  
Author(s):  
Changjiu Wang ◽  
Huiqing Liu ◽  
Qiang Zheng ◽  
Yongge Liu ◽  
Xiaohu Dong ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Three Dimensional ◽  
Heat Stability ◽  
Steam Injection ◽  
Oil Reservoirs ◽  
Steam Flooding ◽  
Profile Control ◽  
Heavy Oil Reservoirs

Controlling the phenomenon of steam channeling is a major challenge in enhancing oil recovery of heavy oil reservoirs developed by steam injection, and the profile control with gel is an effective method to solve this problem. The use of conventional gel in water flooding reservoirs also has poor heat stability, so this paper proposes a new high-temperature gel (HTG) plugging agent on the basis of a laboratory experimental investigation. The HTG is prepared with nonionic filler and unsaturated amide monomer (AM) by graft polymerization and crosslinking, and the optimal gel formula, which has strong gelling strength and controllable gelation time, is obtained by the optimization of the concentration of main agent, AM/FT ratio, crosslinker, and initiator. To test the adaptability of the new HTG to heavy oil reservoirs and the performance of plugging steam channeling path and enhancing oil recovery, performance evaluation experiments and three-dimensional steam flooding and gel profile control experiments are conducted. The performance evaluation experiments indicate that the HTG has strong salt resistance and heat stability and still maintains strong gelling strength after 72 hrs at 200 °C. The singular sand-pack flooding experiments suggest that the HTG has good injectability, which can ensure the on-site construction safety. Moreover, the HTG has a high plugging pressure and washing out resistance to the high-temperature steam after gel forming and keeps the plugging ratio above 99.8% when the following steam injected volume reaches 10 PV after gel breakthrough. The three-dimensional steam flooding and gel profile control experiments results show that the HTG has good plugging performance in the steam channeling path and effectively controls its expanding. This forces the following steam, which is the steam injected after the gelling of HTG in the model, to flow through the steam unswept area, which improves the steam injection profile. During the gel profile control period, the cumulative oil production increases by 294.4 ml and the oil recovery is enhanced by 8.4%. Thus, this new HTG has a good effect in improving the steam injection profile and enhancing oil recovery and can be used to control the steam channeling in heavy oil reservoirs.

Synthesis and Characterization Performance of a Novel High Temperature Retarder Applied in Long Cementing Interval

2016 ◽  
Vol 847 ◽  
pp. 479-484 ◽  
Author(s):  
Ya Lu ◽  
Ming Li ◽  
Zi Han Guo ◽  
Xiao Yang Guo
Keyword(s):  
Thermal Stability ◽  
Compressive Strength ◽  
High Temperature ◽  
Temperature Difference ◽  
Ph Value ◽  
Rapid Development ◽  
Large Temperature ◽  
Gravimetric Analysis ◽  
Sedimentation Stability ◽  
Large Temperature Difference

In view of the common polymer retarder of AMPS has poor sedimentation stability for slurry in high temperature, and thickening curve for unusual problems, a new terpolymers retarder PSIH which can solve the problem for the large temperature difference was synthesized by free radical aqueous solution copolymerization using styrene sulfonate (SSS), Itaconic acid (IA) and unsaturated hydroxyl ester monomers X . The structure and thermal stability of the copolymer was characterized with gel permeation chromatography (GPC), infrared spectroscopy (IR), and thermal gravimetric analysis (TG). The application performance of the retarder was assessed. The results demonstrated as follows. 1) The preferred synthesis conditions of the retarder is: the mass ratio of SSS/IA/X=9: 3: 1, temperature=60°C, initiator concentration =2%, the reaction time=5h, pH value was controlled in the neutral bias acidity. 2) Synthetic copolymer is the target product with appropriate molecular weight and has good thermal stability with thermal decomposition temperature of the main chain up to 375°C. 3) Compared with ordinary retarder the PSIH has merits as follows: excellent thermal resistant ability and sedimentation stability in high temperature; the rapid development of compressive strength in low temperature, and a big temperature span (30 °C~150 °C). The thickening time of the slurry with 1.0% PSIH is 245 min at 150°C; the compressive strength of cement with the same dosage can get up to 4.7MPa at 30 °C. In short, PSIH has excellent ability to cope with large temperature difference, providing a strong technical support for complex deep well cementing.

scholarly journals Experimental Study on Expansion Characteristics of Core-Shell and Polymeric Microspheres

2018 ◽  
Vol 2018 ◽  
pp. 1-9 ◽  
Author(s):  
Pengxiang Diwu ◽  
Baoyi Jiang ◽  
Jirui Hou ◽  
Zhenjiang You ◽  
Jia Wang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Early Stage ◽  
Average Diameter ◽  
Control Agent ◽  
Field Application ◽  
Experimental Results ◽  
Core Shell ◽  
The Core ◽  
Profile Control ◽  
Polymeric Microsphere

Traditional polymeric microsphere has several technical advantages in enhancing oil recovery. Nevertheless, its performance in some field application is unsatisfactory due to limited blockage strength. Since the last decade, novel core-shell microsphere has been developed as the next-generation profile control agent. To understand the expansion characteristic differences between these two types of microspheres, we conduct size measurement experiments on the polymeric and core-shell microspheres, respectively. The experimental results show two main differences between them. First, the core-shell microsphere exhibits a unimodal distribution, compared to multimodal distribution of the polymeric microsphere. Second, the average diameter of the core-shell microsphere increases faster than that of the polymeric microsphere in the early stage of swelling, that is, 0–3 days. These two main differences both result from the electrostatic attraction between core-shell microspheres with different hydration degrees. Based on the experimental results, the core-shell microsphere is suitable for injection in the early stage to block the near-wellbore zone, and the polymeric microsphere is suitable for subsequent injection to block the formation away from the well. A simple mathematical model is proposed for size evolution of the polymeric and core-shell microspheres.

Experimental Study on High Temperature-Resistant Gel for Profile Control

2015 ◽  
Vol 733 ◽  
pp. 165-168 ◽  
Author(s):  
Shao Bin Hu ◽  
Peng Wang ◽  
Chang Liang Chen ◽  
Shao Ke Liu ◽  
Zhe Wang
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Volume Fraction ◽  
Crosslinking Agent ◽  
Reservoir Water ◽  
Good Thermal Stability ◽  
Heat Stabilizer ◽  
Profile Control ◽  
Weak Gel ◽  
Gel System

In order to control water and increase oil recovery in reservoir of high temperature (120°C), experiments were carried out to study the impacts of dosage of HPAM, crosslinking agent, delayed crosslinking agent and heat stabilizer on the properties of gel system, and a high temperature-resistant movable weak gel profile control system was presented, whose formula is 2.0g/L HPAM + 0.2% (volume fraction) crosslinking agent + 0.1g/L delayed crosslinking agent + 0.1g/L heat stabilizer. This gel system has good thermal stability at 120°C. It has good flow properties before gelation, and can effectively enter larger pores. After gelation, its viscosity increases so significantly that it can be stranded and the larger pores can be plugged. The plugging rate can be over 93%. Thus, subsequent fluid injection can be redirected into the low-permeability layers, effectively improving the reservoir water absorption profile and oil recovery.

Novel Profile Control Treatment Using Pore-Scale Polymer Elastic Microspheres

2013 ◽  
Vol 716 ◽  
pp. 413-417 ◽  
Author(s):  
Lei Li ◽  
Xue Mei Gao ◽  
Guang Lun Lei ◽  
Xiao Dong Wei
Keyword(s):  
Aqueous Solution ◽  
Oil Recovery ◽  
Water Injection ◽  
Control Agent ◽  
Control Treatment ◽  
Pore Scale ◽  
Swelling Property ◽  
Profile Control ◽  
Heterogeneous Formation ◽  
Deep Profile

In order to solve the deep profile control problem and improve oil recovery of the oilfield, a novel profile control agent pore-scale polymer elastic microspheres (PSPEMs) was synthesized. The swelling property of PSPEMs in aqueous solution was analyzed. Core flow test and double-tube sand pack models were used for studying profile control and flooding performance of PSPEMs in oil formation. The results show that PSPEMs have good swelling property in aqueous solution with high salinity, high temperature and high pressure. Fig 5 and Fig 6 show that PSPEMs are better than polyacrylamide polymer on profile control. Table 1 indicates PSPEMs can improve water injection profile of heterogeneous formation effectively and plug the high permeable layer first. The higher the concentration of PSPEMs, the shorter the time it spends to realize profile control. The results also confirm that use proper concentration of PSPEMs, the profile control efficiency can increase enormously.

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