The Combined Flooding of Dispersed Particle Gel and Surfactant for Conformance Control and EOR: From Experiment to Pilot Test

2021 ◽  
Author(s):  
Xia Yin ◽  
Tianyi Zhao ◽  
Jie Yi
Keyword(s):  
Oil Recovery ◽  
Formation Energy ◽  
High Salinity ◽  
Surfactant Solution ◽  
Pilot Test ◽  
Control Performance ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Conformance Control ◽  
And Performance

Abstract The water channeling and excess water production led to the decreasing formation energy in the oilfield. Therefore, the combined flooding with dispersed particle gel (DPG) and surfactant was conducted for conformance control and enhanced oil recovery in a high temperature (100-110°C) high salinity (>2.1×105mg/L) channel reservoir of block X in Tahe oilfield. This paper reports the experimental results and pilot test for the combined flooding in a well group of Block X. In the experiment part, the interfacial tension, emulsifying capacity of the surfactant and the particle size during aging of DPG were measured, then, the conformance control and enhanced oil recovery performance of the combined flooding was evaluated by core flooding experiment. In the pilot test, the geological backgrounds and developing history of the block was introduced. Then, an integrated study of EOR and conformance control performance in the block X are analyzed by real-time monitoring and performance after treatment. In addition, the well selection criteria and flooding optimization were clarified. In this combined flooding, DPG is applied as in-depth conformance control agent to increase the sweep efficiency, and surfactant solution slug following is used for improve the displacement efficiency. The long term stability of DPG for 15 days ensures the efficiency of in-depth conformance control and its size can increase from its original 0.543μm to 35.5μm after aging for 7 days in the 2.17×105mg/L reservoir water and at 110°C. In the optimization, it is found that 0.35% NAC-1+ 0.25% NAC-2 surfactant solution with interfacial tension 3.2×10-2mN/m can form a relatively stable emulsion easily with the dehydrated crude oil. In the double core flooding, the conformance control performance is confirmed by the diversion of fluid after combined flooding and EOR increases by 21.3%. After exploitation of Block X for 14 years, the fast decreasing formation energy due to lack of large bottom water and water fingering resulted in a decreasing production rate and increasing watercut. After combined flooding in Y well group with 1 injector and 3 producers, the average dynamic liquid level, daily production, and tracing agent breakthrough time increased, while the watercut and infectivity index decreased. The distribution rate of injected fluid and real-time monitoring also assured the conformance control performance. The oil production of this well group was increased by over 3000 tons. Upon this throughout study of combined flooding from experiment to case study, adjusting the heterogeneity by DPG combined with increasing displacement efficiency of surfactant enhanced the oil recovery synergistically in this high salinity high temperature reservoir. The criteria for the selection and performance of combined flooding also provides practical experiences and principles for combined flooding.

scholarly journals Modification of Xanthan Gum for a High-Temperature and High-Salinity Reservoir

Polymers ◽  
2021 ◽  
Vol 13 (23) ◽  
pp. 4212
Author(s):  
Mohamed Said ◽  
Bashirul Haq ◽  
Dhafer Al Shehri ◽  
Mohammad Mizanur Rahman ◽  
Nasiru Salahu Muhammed ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Xanthan Gum ◽  
Elevated Temperatures ◽  
High Salinity ◽  
Residual Oil ◽  
Core Flooding ◽  
Nacl Solution ◽  
The Core ◽  
Tertiary Oil Recovery

Tertiary oil recovery, commonly known as enhanced oil recovery (EOR), is performed when secondary recovery is no longer economically viable. Polymer flooding is one of the EOR methods that improves the viscosity of injected water and boosts oil recovery. Xanthan gum is a relatively cheap biopolymer and is suitable for oil recovery at limited temperatures and salinities. This work aims to modify xanthan gum to improve its viscosity for high-temperature and high-salinity reservoirs. The xanthan gum was reacted with acrylic acid in the presence of a catalyst in order to form xanthan acrylate. The chemical structure of the xanthan acrylate was verified by FT-IR and NMR analysis. The discovery hybrid rheometer (DHR) confirmed that the viscosity of the modified xanthan gum was improved at elevated temperatures, which was reflected in the core flood experiment. Two core flooding experiments were conducted using six-inch sandstone core plugs and Arabian light crude oil. The first formulation—the xanthan gum with 3% NaCl solution—recovered 14% of the residual oil from the core. In contrast, the modified xanthan gum with 3% NaCl solution recovered about 19% of the residual oil, which was 5% higher than the original xanthan gum. The xanthan gum acrylate is therefore more effective at boosting tertiary oil recovery in the sandstone core.

scholarly journals Low-tension gas process in high-salinity and low-permeability reservoirs

2020 ◽  
Vol 17 (5) ◽  
pp. 1329-1344
Author(s):  
Alolika Das ◽  
Nhut Nguyen ◽  
Quoc P. Nguyen
Keyword(s):  
Oil Recovery ◽  
High Salinity ◽  
Oxidative Degradation ◽  
Qualitative Assessment ◽  
Low Permeability ◽  
Displacement Efficiency ◽  
Fractional Flow ◽  
Hydrocarbon Gases ◽  
Low Tension ◽  
Low Permeability Reservoirs

Abstract Polymer-based EOR methods in low-permeability reservoirs face injectivity issues and increased fracturing due to near wellbore plugging, as well as high-pressure gradients in these reservoirs. Polymer may cause pore blockage and undergo shear degradation and even oxidative degradation at high temperatures in the presence of very hard brine. Low-tension gas (LTG) flooding has the potential to be applied successfully for low-permeability carbonate reservoirs even in the presence of high formation brine salinity. In LTG flooding, the interfacial tension between oil and water is reduced to ultra-low values (10−3 dyne/cm) by injecting an optimized surfactant formulation to maximize mobilization of residual oil post-waterflood. Gas (nitrogen, hydrocarbon gases or CO2) is co-injected along with the surfactant slug to generate in situ foam which reduces the mobility ratio between the displaced (oil) and displacing phases, thus improving the displacement efficiency of the oil. In this work, the mechanism governing LTG flooding in low-permeability, high-salinity reservoirs was studied at a microscopic level using microemulsion properties and on a macroscopic scale by laboratory-scale coreflooding experiments. The main injection parameters studied were injected slug salinity and the interrelation between surfactant concentration and injected foam quality, and how they influence oil mobilization and displacement efficiency. Qualitative assessment of the results was performed by studying oil recovery, oil fractional flow, oil bank breakthrough and effluent salinity and pressure drop characteristics.

Asphaltene Deposition Induced by Carbon Oxide and its Influence on Displacement Efficiency

2012 ◽  
Vol 594-597 ◽  
pp. 2451-2454
Author(s):  
Feng Lan Zhao ◽  
Ji Rui Hou ◽  
Shi Jun Huang
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Carbon Oxide ◽  
Viscosity Reduction ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Oil Composition ◽  
Oil Viscosity ◽  
Asphaltene Deposition ◽  
Total Oil

CO2is inclined to dissolve in crude oil in the reservoir condition and accordingly bring the changes in the crude oil composition, which will induce asphaltene deposition and following formation damage. In this paper, core flooding device is applied to study the effect of asphaltene deposition on flooding efficiency. From the flooding results, dissolution of CO2into oil leads to recovery increase because of crude oil viscosity reduction. But precipitated asphaltene particles may plug the pores and throats, which will make the flooding effects worse. Under the same experimental condition and with equivalent crude oil viscosity, the recovery of oil with higher proportion of precipitated asphaltene was relatively lower during the CO2flooding, so the asphltene precipitation would affect CO2displacement efficiSubscript textency and total oil recovery to some extent. Combination of static diffusion and dynamic oil flooding would provide basic parameters for further study of the CO2flooding mechanism and theoretical evidence for design of CO2flooding programs and forecasting of asphaltene deposition.

Evaluation of Foam-Gels for Conformance Control in High Temperature High Salinity Carbonates

2021 ◽  
Author(s):  
Lyla Almaskeen ◽  
Abdulkareem AlSofi ◽  
Jinxun Wang ◽  
Ziyad Kaidar
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Concentration Ratio ◽  
High Salinity ◽  
Fractured Reservoirs ◽  
Gelation Time ◽  
Resistance Factor ◽  
Naturally Fractured Reservoirs ◽  
Conformance Control ◽  
Wide Range

Abstract In naturally fractured reservoirs, conformance control prior to enhanced oil recovery (EOR) application might be essential to ensure optimal contact and sufficient sweep. Recently, few studies investigated combining foams and gels into what is commonly coined as foamed-gels. Foamed-gels have been tested and shown to be potential for some field conditions. Yet, very limited studies were performed for high temperature and high salinity carbonates. Therefore, in this work, we study the potential of foamed-gels for high temperature and high salinity carbonates. The objective is to evaluate the potential of such synergy and to compare its value to the individual processes. For that purpose, in this work, we rely on bulk and core-scale tests. Bulk tests were used for initial screening. Wide range of foam-gel solutions were prepared with different polymer types and polymer concentrations. Test tubes were hand shacked thoroughly to generate foams. Foam heights were then measured from the test tubes. Heights were used to screen foaming agents and to study gelant effects on foamers in terms of foam strength (heights). The effect of foamers on gelation was evaluated through bottle tests. Based on the results, an optimal concentration ratio of gelant to foamer was determined and used in core-scale displacements, to further study the potential of this hybrid foam-gel process. Bulk results suggested that addition of the gelant up to a 4:1 foam to gel concentration ratio resulted in sufficient foam generation in some of the polymer samples. Yet, only two of the foam-gel samples generated a strong gel. Increasing the foamer concentration delayed the gelation time and in some samples, the solution did not gel. Through the coreflooding experiment, resistance factor (RF) and residual resistance factor (RRF) were obtained for different conformance control processes including foam, foam-gel, and gel. Foam-gel injection exhibited higher RF and RRF values than conventional foams. However, conventional gels showed even higher RF and RRF values than foam-gels. Combining two of the most widely used conformance control methods (foams and gels) can strike a balance. Foam-gel may offer a treatment that is deeper and more sustainable than foams and on the other a treatment that is more practical, and lower-cost than gels. Our laboratory results also demonstrate that such synergetic conformance control can be achieved in high salinity and high temperature carbonates with pronounced impact.

A New Hybrid Improved and Enhanced Oil Recovery IOR/EOR Process Using Smart Water Assisted Foam SWAF Flooding in Carbonate Rocks; A Laboratory Study Approach

2021 ◽  
Author(s):  
Anas. M. Hassan ◽  
Mohammed Ayoub ◽  
Mysara Eissa ◽  
Hans Bruining ◽  
Abdullah Al-Mansour ◽  
...  
Keyword(s):  
Aqueous Solution ◽  
Oil Recovery ◽  
Type A ◽  
Crude Oils ◽  
Residual Oil ◽  
Type B ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Smart Water ◽  
Surfactant Aqueous Solution

Abstract Given the increasing demand for energy globally and depleting oil and gas resources, it is crucial to increase the production from existing reservoirs by introducing new technologies for Improved/Enhanced Oil Recovery (IOR/EOR). This contribution presents a novel hybrid IOR/EOR method, which combines smart water (SW) and foam flooding, known as Smart Water Assisted Foam (SWAF) flooding. The optimal conditions of the SWAF technology will be interpreted using experimental laboratory design (i.e., experimental data). The experimental design was divided into three main steps. The first step is obtaining rock wettability measurements using contact angle measurements. This step aims to select the optimum SW composition that changes the carbonate rock's wettability from oil-wet towards more water-wet and faster oil recoveries. The water-wet condition leads to high residual oil saturations and low end-point permeabilities. This is conductive to favourable mobility ratios and efficient water-oil displacement. However, high residual oil saturations are unfavourable to the high ultimate oil recovery as much oil stays behind. Secondly, the chemical screening follows, where two tests were performed, viz., (i) an Aqueous Stability Test (AST), (ii) and a Foamability and Foam Stability Tests (FT/FST). This step aims to generate a stable foam (i.e., surfactant aqueous solution + gas) in the absence and presence of crude oil with different TAN (Total Acid Number) and TBN (Total Base Number), viz., crude oils Type-A and Type-B. Favourable mobility ratio is achieved by the presence of foam, which leads to excellent displacement efficiency. Thirdly, core flooding tests are performed. This step aims to select the best formulations through SWAF core flooding tests to obtain the ultimate recovery factor under different injection scenarios. The optimal SWAF condition combines high ultimate recovery with the best displacement efficiency. It is shown that the enormous changes in wettability were seen for SW (MgCl2) solution at 3500 (ppm) for both crude oils Type-A and Type-B. It has been shown that the use of a cationic surfactant CTAB (i.e., cetyltrimethylammonium-bromide) in the positively charged carbonates (with an isoelectric point of pH = 9) is more effective than the use of anionic surfactant, e.g., Alpha Olefin Sulfonate (AOS). The aim is to create an optimum surfactant aqueous solution (SAS). The SAS stability is considerably affected by the concentration of both the SW (MgCl2) and surfactant (CTAB). In the absence of oil, the strength of foam (SAS and Gas) is highly dependent on the concentration and composition of the SW in the SAS. In the presence of oil, foam generation and stability are better when the crude oil has a low TAN and high TBN. From the core flooding tests for crude oils Type-A and Type-B, the ultimate residual oil recovery was achieved by the MgCl2 - foam injection combination (i.e., incremental oil recovery of 42%, which is equivalent to a cumulative oil recovery of 92%). In summary, SWAF under the optimum conditions is a promising method to increase the oil recovery from carbonate reservoirs.

Carbon Dots Stabilized Foam for Enhanced Oil Recovery

2021 ◽  
Author(s):  
Sivabalan Sakthivel ◽  
Mazen Kanj
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
High Salinity ◽  
Foam Stability ◽  
Surfactant Solution ◽  
Oil And Gas Industry ◽  
Mobility Control ◽  
Carbon Nanodots ◽  
High Permeability ◽  
Drainage Rate

Abstract Foams are the divergent fluids that are employed in the upstream oil and gas industry to reduce fluid channeling and fingering in the high permeability region. Foams are usually generated in the high permeability reservoirs (e.g. glass beads) by the alternative injection of surfactant and gas. Conventional foaming systems exhibit stability issues at the high temperature and high salinity reservoir conditions. In this investigation, we study the stability and efficiency (in terms of both enhanced inflow performance and added oil recovery) of foams formed using surfactant solution with and without carbon Nanodots (CND). The study involved using different brine salinities, CND concentrations, temperature and pressure conditions, and types of surfactants. A multifaceted interrelationship of the various influencing mechanisms is demonstrated. Foams are examined using foam analyzer, HP/HT coreflood and microfluidic setup. In trace amounts (5-10 ppm), CND contributed to 60-70% improvement in foam stability in high salinity brine. The improvement is attributed by the reduction of the drainage rate of the lamellae and a delay of the bubble rupturing point. Both microfluidic and core-flood experiments showed noticeable improvement in mobility control with the addition of the CND. This is contributed to an improved foamability, morphology, strength, and stability of the foam.

Novel Enhanced Oil Recovery Method Using Co2+xFe2+1-xFe3+2O4 as Magnetic Nanoparticles Activated by Electromagnetic Waves

2013 ◽  
Vol 26 ◽  
pp. 111-116 ◽  
Author(s):  
Hasan Soleimani ◽  
Noorhana Yahya ◽  
Noor Rasyada Ahmad Latiff ◽  
Hasnah Mohd Zaid ◽  
Birol Demiral ◽  
...  
Keyword(s):  
Magnetic Nanoparticles ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Electromagnetic Waves ◽  
High Salinity ◽  
Harsh Environment ◽  
Oil Reservoir ◽  
Core Flooding ◽  
Recovery Method ◽  
High Pressure And Temperature

Research on the application of nanoparticles, specifically magnetic nanoparticles in enhanced oil recovery has been increasing in recent years due to their potential to increase the oil production despite having to interact with reservoirs of high salinity, high pressure and temperature and un-natural pH. Unlike other conventional EOR agents e.g. surfactants and polymers, a harsh environment will cause degradation and failure to operate. Magnetic nanoparticles which are activated by a magnetic field are anticipated to have the ability to travel far into the oil reservoir and assist in the displacement of the trapped oil. In this work, ferromagnetic Co2+xFe2+1-xFe3+2O4 nanoparticles were synthesized and characterized for their morphological, structural and magnetic properties. At a composition x = 0.75, this nanomaterial shows its best magnetisation parameters i.e. highest value of saturation magnetization, remanence and coercivity of 65.23 emu/g, 12.18 emu/g and 239.10 Oe, respectively. Subsequently, a dispersion of 0.01 wt% Co2+0.75Fe2+0.25Fe3+2O4 nanoparticles in distilled water was used for core flooding test to validate its feasibility in enhanced oil recovery. In a core flooding test, the effect of electromagnetic waves irradiation to activate the magnetization of Co2+0.75Fe2+0.25Fe3+2O4 nanofluid was also investigated by irradiating a 78 MHz square wave to the porous medium while nanofluid injection was taking place. In conclusion, an almost 20% increment in the recovery of oil was obtained with the application of electromagnetic waves in 2 pore volumes injection of a Co2+0.75Fe2+0.25Fe3+2O4 nanofluid.

scholarly journals Synthesis and Performance of an Acrylamide Copolymer Containing Nano-SiO2as Enhanced Oil Recovery Chemical

2013 ◽  
Vol 2013 ◽  
pp. 1-10 ◽  
Author(s):  
Zhongbin Ye ◽  
Xiaoping Qin ◽  
Nanjun Lai ◽  
Qin Peng ◽  
Xi Li ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Raw Materials ◽  
Retention Rate ◽  
Resistance Factor ◽  
Mobility Control ◽  
Core Flooding ◽  
Residual Resistance ◽  
H Nmr ◽  
And Performance

A novel copolymer containing nano-SiO2was synthesized by free radical polymerization using acrylamide (AM), acrylic acid (AA), and nano-SiO2functional monomer (NSFM) as raw materials under mild conditions. The AM/AA/NSFM copolymer was characterized by infrared (IR) spectroscopy,1H NMR spectroscopy, elemental analysis, and scanning electron microscope (SEM). It was found that the AM/AA/NSFM copolymer exhibited higher viscosity than the AM/AA copolymer at 500 s−1shear rate (18.6 mPa·s versus 8.7 mPa·s). It was also found that AM/AA/NSFM could achieve up to 43.7% viscosity retention rate at 95°C. Mobility control results indicated that AM/AA/NSFM could establish much higher resistance factor (RF) and residual resistance factor (RRF) than AM/AA under the same conditions (RF: 16.52 versus 12.17, RRF: 3.63 versus 2.59). At last, the enhanced oil recovery (EOR) of AM/AA/NSFM was up to 20.10% by core flooding experiments at 65°C.

Conformance control for production optimisation using polymer nanocomposite hydrogels

2020 ◽  
Vol 60 (2) ◽  
pp. 658
Author(s):  
Reza M. Rudd ◽  
Ali Saeedi ◽  
Colin D. Wood
Keyword(s):  
Oil Recovery ◽  
Preferential Flow ◽  
Polymer Nanocomposite ◽  
Nanocomposite Hydrogel ◽  
Core Flooding ◽  
Conformance Control ◽  
Hydrocarbon Recovery ◽  
Polymer Hydrogels ◽  
Nanocomposite Hydrogels ◽  
Pass Through

Conformance control is a major challenge in hydrocarbon recovery operations. One of the effective technologies for improving the conformance of a flood front and modifying the injected fluid profile is the application of polymer hydrogels. In this technique, polymer hydrogels are prepared as gel particles, which are injected into the reservoir to block-off preferential flow paths and thief zones, such as fractures and high permeability zones. Subsequently, the fluid injected as part of oil recovery operation would be directed and forced to pass through low permeable zones and sweep more hydrocarbon mass towards the production wells. Depending on the situation, this technology can result in a considerable incremental hydrocarbon recovery from a reservoir. In the present research, nanotechnology was combined with polymer engineering to develop a novel polymer nanocomposite hydrogel with supreme properties, as confirmed using advanced rheological characterisation. Subsequently, the performance of the newly developed nanocomposite hydrogel was tested using a specially designed core flooding setup and procedure. The core flooding results showed that the application of this novel hydrogel could increase the oil recovery by up to 16% under laboratory conditions.

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