scholarly journals A Study on the Morphology of a Dispersed Particle Gel Used as a Profile Control Agent for Improved Oil Recovery

2014 ◽  
Vol 2014 ◽  
pp. 1-9 ◽  
Author(s):  
Qing You ◽  
Yongchun Tang ◽  
Caili Dai ◽  
Mingwei Zhao ◽  
Fulin Zhao
Keyword(s):  
Oil Recovery ◽  
Mass Concentration ◽  
Oil And Gas ◽  
Dlvo Theory ◽  
Control Agent ◽  
Gas Field ◽  
Improved Oil Recovery ◽  
Shearing Rate ◽  
Initial Polymer ◽  
Profile Control

To achieve in-depth profile control of injection water and improve oil recovery, a new profile control agent, termed as dispersed particle gel (DPG), has been developed and reported. In this paper, the morphology of DPG and the factors that influence its morphology are systematically investigated using atomic force microscopy (AFM). The AFM studies show that DPG is composed of small pseudospherical particles and that their sizes can be controlled by adjusting the shearing rate, the initial polymer mass concentration, and the salinity. Dynamic light scattering (DLS) is used to study the effects of the initial polymer mass concentration, the shearing rate, the salinity, and the high-temperature aging on the particle size of DPG. The aggregation ability of DPG is explained using the DLVO theory and space stability theory. This work provides a scientific basis and technical support for the formula design of DPG and its application in the oil and gas field.

scholarly journals Overview of Polymers for Improved Oil Recovery Treatments

2020 ◽  
Author(s):  
Mohamed Saeed Shamlooh1 ◽  
Ahmed Hamza ◽  
Ibnelwaleed Hussein ◽  
Mustafa Nasser ◽  
Saeed Salehi
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
High Efficiency ◽  
High Water ◽  
High Permeability ◽  
Chemical Methods ◽  
Improved Oil Recovery ◽  
Profile Modification ◽  
Fractured Carbonate ◽  
Deep Profile

High water production in oil and gas wells reduces significantly the recovery factor. Mechanical as well as chemical methods are applied to shut off water productive zones. Crosslinked polymers showed high efficiency to seal off water zones in high permeability sandstone and fractured carbonate reservoirs. Moreover, emulsified polymeric formulations have been introduced for deep profile modification by changing the wettability of the rock and hence allowing selective plugging of water. This poster provides an overview of the polymeric formulations used for such application.

An Experimental Research on Enhanced Oil Recovery Using Local Polymers

2021 ◽  
Author(s):  
Abiola Oyatobo ◽  
Amalachukwu Muoghalu ◽  
Chinaza Ikeokwu ◽  
Wilson Ekpotu
Keyword(s):  
Enhanced Oil Recovery ◽  
Experimental Research ◽  
Oil Recovery ◽  
Capital Investment ◽  
Oil And Gas ◽  
Produced Water ◽  
Water Injection ◽  
Gum Arabic ◽  
Oil And Gas Industry ◽  
Profile Control

Abstract Ineffective methods of increasing oil recovery have been one of the challenges, whose solutions are constantly sought after in the oil and gas industry as the number of under-produced reservoirs increases daily. Water injection is the most extended technology to increase oil recovery, although excessive water production can pose huge damage ranging from the loss of the well to an increase in cost and capital investment requirement of surface facilities to handle the produced water. To mitigate these challenges and encourage the utilization of local contents, locally produced polymers were used in polymer flooding as an Enhanced Oil Recovery approach to increase the viscosity of the injected fluids for better profile control and reduce cost when compared with foreign polymers as floppan. Hence this experimental research was geared towards increasing the efficiency of oil displacement in sandstone reservoirs using locally sourced polymers in Nigeria and also compared the various polymers for optimum efficiency. Starch, Ewedu, and Gum Arabic were used in flooding an already obtained core samples and comparative analysis of this shows that starch yielded the highest recovery due to higher viscosity value as compared to Ewedu with the lowest mobility ratio to Gum Arabic. Finally, the concentration of Starch or Gum Arabic should be increased for optimum recovery.

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.

scholarly journals Beyond Carbon Steel: Detecting Wellbore Shape and Cavities, and Cement Imperfections in Cased Wells

Energies ◽  
2019 ◽  
Vol 12 (21) ◽  
pp. 4211
Author(s):  
Timofey Eltsov ◽  
Tadeusz W. Patzek
Keyword(s):  
Magnetic Field ◽  
Carbon Steel ◽  
Oil Recovery ◽  
Magnetic Permeability ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Carbon Capture And Storage ◽  
Vertical Component ◽  
Co2 Injection ◽  
Gas Field

The non-corrosive, electrically resistive fiberglass casing materials may improve the economics of oil and gas field projects. At moderate temperatures (<120 °C), fiberglass casing is superior to carbon steel casing in applications that involve wet CO2 injection and/or production, such as carbon capture and storage, and CO2-based enhanced oil recovery (EOR) methods. Without a perfect protective cement shell, carbon steel casing in contact with a concentrated formation brine corrodes and the fiberglass casing is superior again. Fiberglass casing enables electromagnetic logging for exploration and reservoir monitoring, but it requires the development of new logging methods. Here we present a technique for the detection of integrity of magnetic cement behind resistive fiberglass casing. We demonstrate that an optimized induction logging tool can detect small changes in the magnetic permeability of cement through a non-conductive casing in a vertical (or horizontal) well. We determine both the integrity and solidification state of the cement-filled annulus behind the casing. Changes in magnetic permeability influence mostly the real part of the vertical component of the magnetic field. The signal amplitude is more sensitive to a change in the magnetic properties of the cement, rather than the signal phase. Our simulations showed that optimum separation between the transmitter and receiver coils ranged from 0.25 to 0.6 m, and the most suitable magnetic field frequencies varied from 0.1 to 10 kHz. A high-frequency induction probe operating at 200 MHz can measure the degree of solidification of cement. The proposed method can detect borehole cracks filled with cement, incomplete lift of cement, casing eccentricity, and other borehole inhomogeneities.

Petroleum Reservoirs

1996 ◽  
Author(s):  
Craig M. Bethke
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Saline Water ◽  
Fluid Pressure ◽  
Petroleum Reservoirs ◽  
Hot Water ◽  
Reservoir Rock ◽  
Mineral Surfaces ◽  
Improved Oil Recovery ◽  
Mineral Scale

In efforts to increase and extend production from oil and gas fields, as well as to keep wells operational, petroleum engineers pump a wide variety of fluids into the subsurface. Fluids are injected into petroleum reservoirs for a number of purposes, including: • Waterflooding, where an available fresh or saline water is injected into the reservoir to displace oil toward producing wells. • Improved Oil Recovery (IOR), where a range of more exotic fluids such as steam (hot water), caustic solutions, carbon dioxide, foams, polymers, surfactants, and so on are injected to improve recovery beyond what might be obtained by waterflooding alone. • Near-well treatments, in which chemicals are injected into producing and sometimes injector wells, where they are intended to react with the reservoir rock. Well stimulation techniques such as acidization, for example, are intended to increase the formation's permeability. Alternatively, producing wells may receive “squeeze treatments” in which a mineral scale inhibitor is injected into the formation. In this case, the treatment is designed so that the inhibitor sorbs onto mineral surfaces, where it can gradually desorb into the formation water during production. • Pressure management, where fluid is injected into oil fields in order to maintain adequate fluid pressure in reservoir rocks. Calcium carbonate may precipitate as mineral scale, for example, if pressure is allowed to deteriorate, especially in fields where formation fluids are rich in Ca++ and HCO3- and CO2 fugacity is high. In each of these procedures, the injected fluid can be expected to be far from equilibrium with sediments and formation waters. As such, it is likely to react extensively once it enters the formation, causing some minerals to dissolve and others to precipitate. Hutcheon (1984) appropriately refers to this process as “artificial diagenesis,” drawing an analogy to the role of groundwater flow in the diagenesis of natural sediments (see Chapter 19). Further reaction is likely if the injected fluid breaks through to producing wells and mixes there with formation waters. There is considerable potential, therefore, for mineral scale, such as barium sulfate (see the next section), to form during these procedures.

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.

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.

scholarly journals Experimental Investigation of Self-Assembled Particles on Profile Control in the Fuyu Oilfield

2021 ◽  
Vol 9 ◽  
Author(s):  
Lifei Dong ◽  
Miao Wang ◽  
Jie He ◽  
Mingchen Ding ◽  
Hun Lin
Keyword(s):  
Oil Recovery ◽  
Particle System ◽  
Water Channel ◽  
Control Agent ◽  
The Self ◽  
Control Effect ◽  
Water Breakthrough ◽  
Profile Control ◽  
Self Assembled ◽  
Enhance Oil Recovery

The particle system is one of the widely used profile control agents in many oilfields, and the matching relationship between the particle and the reservoir pore throat is significant for the profile control effect. In order to enhance oil recovery after water breakthrough in the Fuyu oilfield, a self-assembled particle with some branches on the surface, compounded by inverse emulsion polymerization and added, is introduced as the profile control agent in this paper. Then the permeabilities of the water channel and the oil remaining area in the Fuyu oilfield are achieved after the statistic analysis of 1,022 cores from the practical reservoir. Furthermore, the oil restarting pressure in the oil remaining area and the self-assembled particle plugging strength in the water channel are tested. Finally, the adaption of the self-assembled particle and effect of profile control in the Fuyu oilfield are evaluated by comparing the oil restarting pressure and the plugging strength. The results show that the self-assembled particles can be gathered together easily by the force of the ionic bond, which is good for water channel plugging. The permeability of the water channel in the Fuyu oilfield ranges from 1,000 mD to 1,500 mD. The oil restarting pressure increases with the decreasing of permeability, and the increasing rate grows rapidly when it drops below 50 mD. Comparing the oil restarting pressure with the plugging strength, a self-assembled particle with a diameter of 20–40 μm in the water channel with a permeability of 1,265.7 mD can provide sufficient plugging strength to restart the remaining oil in the oil remaining areas with a permeability over 3.38 mD. The matched window of the self-assembled particle is wider than a normal particle in the Fuyu oilfield.

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