bluuebunny/crossref_metadata_2025 huggingface dataset:
Current Developments and Remaining Challenges of Chemical Flooding EOR Techniques in China
Authors: Zhu Youyi
Published: August 2015

Chemical flooding EOR techniques, mainly including polymer flooding, chemical combination flooding and foam flooding, play a crucial role in Chinese oil industry. Field tests proved that chemical flooding EOR techniques could be applied successfully in onshore reservoirs in China. Challenges were also presented as the chemical flooding EOR were applied in different reservoirs. The current developments of chemical flooding EOR techniques were introduced, the chemical flooding field tests were summarized and remaining challenges were discussed in this paper.

Polymer flooding has entered into commercial applications stage. By the end of 2011, 54 industrial blocks of polymer flooding have been applied in Daqing Oilfield with 13% incremental oil recovery over water flooding in average. Ten key techniques for polymer flooding have been developed involving polymer screening and evaluation, low viscosity loss facility of injection, high performance polymer preparation and injection equipments and crafts, eccentrically-wearing inhibiting technology, separated layer injection etc. Chemical combination flooding especially ASP flooding has been studied and tested intensively in China. Six pilot and four industrial field tests of ASP flooding have been implemented. More than 20% incremental oil recovery after water flooding has been obtained. A set of techniques for combination flooding have been formed such as ASP formulation optimizing, injection allocation technology, lifting technology, chemicals monitoring of produced liquid etc. Twenty foam flooding pilot tests have been carried out in China, and sixteen of them showed good performances.

Challenges of polymer flooding are mainly focused on the development of new effective polymers for specific reservoir conditions such as high salinity, high temperature, and low permeability reservoirs. The limitations of ASP flooding were known as the scaling problem and difficulty in produced liquid treatment. Challenges in foam flooding were mainly the gas finger problem usually occurred in field tests. Some progresses have been made in recent research and shown good perspectives.
Effects of Emulsification on Oil Recovery and Produced Liquid Handing in Chemical Combination Flooding
Authors: Zhu Youyi , Lei Ming , Zhang Yi
Published: August 2015

It was an argued issue concerning effects of emulsification in chemical combination flooding process. For example, it may increase oil displacement efficiency. On the other hand, it makes the produced liquid handing to be more difficult. How does emulsification impact on oil recovery and produced liquid handing, and how to control emulsification degree are significant issues that are greatly concerned by engineers.

Effect of emulsification on oil recovery of chemical combination flooding was investigated based on emulsification intensity index quantitative measurements and Berea core flooding experiments. Field tests results domestrated that emulsification could remarkably influence oil recovery and produced water handing process.

Core flooding tests showed that enhanced oil recovery by strong alkaline alkali-surfactant-polymer (ASP) flooding, weak alkaline ASP flooding and surfactant-polymer (SP) flooding was different under the same interfacial tension (IFT), viscosity and slug size conditions. The incremental oil recovery after water flooding was about 23%-25%, 20%-23% and 17%-19% respectively as chemical slug size of 0.5PV. The emulsification intensity indexes for different formula were measured. It indicated that the sequence of emulsification intensity index of the three kinds of flooding systems was strong alkaline ASP flooding > weak alkaline ASP flooding > SP flooding. Core flooding experiments of chemical combination flooding with serial emulsification intensity index showed that incremental oil recovery could be increased by 6%-10% with stronger emulsification degree than that with weaker emulsification index.

ASP flooding field tests in Daqing Oilfield showed the different results in incremental oil recovery between strong alkaline ASP and weak alkaline ASP floodings. Emulsion stability of produced liquid from strong alkaline ASP flooding was stronger than that from weak alkaline ASP flooding. The special de-emulsifier and more complicated liquid treatment process were used in strong alkaline ASP flooding field tests. The cost was much higher than that of weak alkaline ASP flooding.

From the above experiments and field tests results, moderate emulsification is necessary for chemical combination flooding. From the view of overall investment and outcome ratio, weak alkaline ASP flooding may be more favorable for expanding application in oilfield than its counterpart of strong alkaline ASP flooding.
Constructing High Productivity Wells with High Wellbore Dynamic Flow Stability for EOR Projects
Authors: Chan Keng Seng , Masoudi Rahim , Karkooti Hooman , Othman Mohamad , Tan Chee Phuat , Anis Apollinaris Stefanus , Press David , Setiawan Ngurah Beni
Published: August 2015

A method of constructing high productivity and high wellbore dynamic stability wells has been developed for EOR field development application. It integrates a heuristic reservoir engineering modelling method for determining optimum drainage points with high dynamic flow and a 3D coupled reservoir geomechanical modelling method for identifying low sanding propensity regions within the entire reservoir. The reservoir geomechanical method couples dynamic reservoir modelling with geomechanical modelling. It can account for in-situ stress changes associated with reservoir pressure change, and predict any potential geomechanical-related physical events for the remaining life of the field. Correspondingly, the generated drainage map and 3D sand production critical drawdown cubes can then be combined to identify global optimum well placement locations within the reservoir, layer by layer.

Drainage points selected by this heuristic reservoir modelling method can be correlated with their respective EUR (Estimated Ultimate Recovery) values, while the 3D critical drawdown cubes can identify reservoir regions with low sanding propensity. This combined approach can therefore lead to the development of multi-layer commingle wells having various angles of reservoir penetration, for optimizing well productivity and EUR value without the requirement of sand control. Illustrated by a case study in brownfield reservoirs, a non-linear well trajectory which maximizes reservoir fluid contact in a prolific sand layer can be designed without any sand control completion for sanding mitigation through optimization and management of production plan.
Technical Challenges in the Conversion of CO2-EOR Projects to CO2 Storage Projects
Authors: Al Eidan A. A. , Bachu S.. , Melzer L. S. , Lars E. I. , Ackiewicz M..
Published: August 2015

While enhanced oil recovery using carbon dioxide (CO2-EOR) is a mature technology and known to concurrently store large volumes of CO2, it is not currently viewed by industry as a CO2 storage process. Application of CO2-EOR for CO2 storage to reduce anthropogenic CO2 emissions 1) enables carbon capture and storage (CCS) technology improvement and cost reduction; 2) improves the business case for CCS demonstration and early movers; 3) supports the development of CO2 transportation networks; 4) may provide significant CO2 storage capacity in the short-to-medium-term, particularly if residual oil zones (ROZ) are produced and hybrid CO2-EOR/CCS operations are considered; 5) enables knowledge transfer; and 6) it helps gaining public and policy-makers acceptance. Although there are a number of commonalities between CO2-EOR and pure CO2 storage operations, currently there are a significant number of differences between the two types of operations that can be grouped in five broad categories: 1) operational; 2) objectives and economics, including CO2 supply, demand and purity; 3) legal and regulatory; 4) long term CO2 monitoring requirements; and 5) industry's experience. There are no specific technological barriers or challenges per se in adapting or converting a pure CO2-EOR operation into a CO2 concurrent or exclusive storage operation. The main differences between the two types of operations stem from legal, regulatory and economic differences between the two. The legal and regulatory framework for CO2 storage is being refined and is still evolving and it is clear that CO2 storage operations will likely require more monitoring and reporting. Because of this, CO2 storage will impose additional costs on the operator. A challenge for existing CO2-EOR operations which may, in the future, adapt to concurrent or exclusive CO2 storage operations is the lack of baseline data for monitoring, except for wellhead and production monitoring for which there is a wealth of data. Thus, in order to facilitate the transition of a pure CO2-EOR operation to concurrent or exclusive CO2 storage, operators and policy makers have to address a series of legal, regulatory and economic issues in the absence of which this transition cannot take place.
A Holistic Approach to EOR Screening in Dual-Porosity Naturally Fractured Reservoirs
Authors: Moreno Jaime E. , Gurpinar O.. , Liu Y..
Published: August 2015

While the principles of enhanced oil recovery (EOR) are not new, field implementation has been scarce, particularly in the case of dual-porosity naturally fractured reservoirs, where the interaction of two different porous media creates a more complex displacement process. Several approaches to define the screening criteria on dual-porosity reservoirs have been postulated; the evaluation of the matrix-fracture interaction still requires complex models for proper EOR selection.

This paper offers a multidimensional approach to EOR selection in dual-porosity naturally fractured reservoirs, starting with a detailed analysis of the matrix-fracture system and including: transmissivity/storativity ratios, fracture geometry, matrix block size, and dominant recovery mechanisms. Historical observations are used for characterization and identification of areas where one porous media is dominant and to help shortlist the desired EOR methods on an area-by-area basis.

Two levels are considered in the analysis: the first level allows for a qualitative EOR ranking, suitable for reservoirs with limited information. The next level (numerically intensive) provides a quantitative EOR ranking with basic economics. The first-level ranking uses four different criteria for the selection—namely, pore-level displacement efficiency of the matrix-fracture system, EOR agent compatibility, matrix-fracture geometry, and the distribution of moveable hydrocarbons—and an internal advisor-system to achieve the ranking based on the fluid and reservoir properties.

A combination of analytical and numerical models is systematically used to overcome the challenge of estimating pore-level displacement efficiency when the EOR agent contacts matrix and fracture systems simultaneously (including all the relevant recovery mechanisms, such as gravity drainage). An advisor system based on a global EOR project database, merged with in-house EOR engineering expertise, complements the EOR selection. Numerical modeling is used at a later stage to further substantiate and quantify the EOR solution, allowing for a full-cycle comparative evaluation.

It is worth mentioning that the advisory EOR system presented here not only tackles a highly challenging topic but also provides “dynamic engineering guidance” throughout the EOR selection process. The authors believe that combining this reliable engineering process with ever-increasing computation power will help our industry to identify EOR potential easily.
Optimization of Gas Assisted Gravity Drainage (GAGD) Process in a Heterogeneous Sandstone Reservoir: Field-Scale Study
Authors: Al-Mudhafar Watheq J. , Rao Dandina N.
Published: August 2015

Gas injection has been widely used for IOR/EOR processes in oil reservoirs. Unlike the conventional modes of continuous gas injection (CGI) and water –alternative gas (WAG), the Gas Assisted Gravity Drainage (GAGD) process takes advantage of the natural segregation of reservoir fluids to provide gravity stable oil displacement. It has been proved that GAGD Process results in better sweep efficiency and higher microscopic displacement to recover the bypassed oil from un-swept reservoir regions. Therefore, CO2 was considered in this research for immiscible injection in the main pay/upper sandstone formation in South Rumaila oil field located in Iraq through the GAGD process application. This field, with a 60-year production history, has 40 production wells and is surrounded by an infiniteacting edge water aquifer from the east and the west flanks. Since the east flank is much less effective than the west one, 20 injection wells have been drilled at the east flank over the last 35 years to maintain the reservoir pressure. The formation depth is 10350 ft. sub-sea with a maximum vertical oil column of 350 ft.

The GAGD process was adopted here using compositional reservoir simulation and PVT modeling to increase oil recovery. The GAGD process consists of placing a horizontal producer near the bottom of the payzone and injecting gas through existing vertical wells that have been used in prior waterfloods. As the injected gas rises to the top to form a gas zone, oil and water drain down to the horizontal producer. The location of horizontal wells is slightly above the oil-water contact.

In the reservoir modeling, different reservoir and fluid properties have been investigated their effect on the flow response to implement sensitivity analysis, history matching through Design of Experiments. The operational design parameters of production/injection wells were considered to determine the optimal future reservoir performance through the GAGD process. Among many prediction scenarios, the GAGD process led to significant recovery incremental, especially in early future production years in comparison with the base case of no injection and 10,000 barrels of water injection per well in the same injection wells.
Development of Novel Surfactant for Alkali-free Surfactant/Polymer Combination Flooding Green Technology
Authors: Zhang Fan , Zhang Qun , Zhou Zhaohui , Cai Hongyan
Published: August 2015

Alkali - surfactant - polymer (ASP) combination flooding technique is one of the effective enhanced oil recovery ways for mature oilfields. However, alkali can lead to difficulty of the scaling and emulsification problems in lifting and produced liquid treatment. So alkali-free surfactant - polymer (SP) combination flooding is a green technology can solve these problems caused by alkali. The key technology of SP flooding is development low cost and high efficiency surfactants. In this paper, the novel betaine surfactant was synthesized with cheap raw material of fatty acid, which had intellectual property and excellent properties. Experimental results showed that the surfactant had wide adaptability and could achieve ultra-low interfacial tension (IFT, less than 1.0×10−2mN/m) in different reservoir conditions, not only for low temperature and low salinity oilfield (45°C, 5,100 mg/L), but also for high temperature and high salinity oilfield (90°C, 100,000 mg/L). The dynamic adsorptions of this betaine were less than 1.0 mg/g rock, and it could maintain ultra-low IFT for 9 times adsorption with the natural sand. The alkali-free SP formulations with the betaine had long term stability, and could maintain ultra-low IFT within 180 days, and the viscosity retention rates were greater than 90%. The systems of the novel betaine surfactant had good emulsifying capacity and stripping film capacity. The alkali-free SP formulations with the betaine had high oil-displacement efficiency. After water flooding, it could increase oil recovery 21.5% (OOIP, Original Oil In Place) in Daqing sandstone oilfield, 23.4% (OOIP) in high temperature and high salinity carbonate reservoir rock, 15.5% (OOIP) in Changqing low permeability oilfield. Excellent properties of this novel betaine surfactant indicate that it is a promising surfactant for alkali-free SP combination flooding applied in different reservoirs.
Alternative Injection and Its Seepage Mechanism of Polymer Flooding in Heterogeneous Reservoirs
Authors: Peihui Han , Haibo Liu , Xu Han , Ruibo Cao , Yuwei Zhang , Xiaoyang Liu
Published: August 2015

Field application proves that polymer flooding is an effective technology for improving development effect of heterogeneous reservoirs. Previously, single slug injection is performed. However, there are problems of profile reverse, non-effective circulation of polymer solution in high permeability zone, over much polymer dosage and so on. Thus a new technique of alternative injection for improving oil displacement effect of polymer flooding is developed. Some oil displacing experiments with different injection patterns are performed by using automatic oil displacement equipment and physical model of heterogeneous reservoir so as to study oil displacement efficiency of different alternative injection patterns. A series of polymer solution slugs with different molecular weight, concentration, viscosity and size are injected alternatively in the experiments and then reasonable alternative injection pattern is optimized and difference of displacement mechanism between single slug injection and alternative injection is illustrated. Meanwhile an evaluation method for the improvement effect of fluid absorption profile is introduced for the first time. Experimental results show that oil displacing effect of alternative injection is better than that of single slug injection and the incremental oil recovery is 2% more than that of single slug injection. Based on basic law of displacement mechanics and combined with experimental data, displacement mechanism of profile reverse and that of inhibiting profile reverse are demonstrated. The profile reverse is mainly due to different tendency of transient resistance factors in high and low permeability zones. Alternative injection can make this tendency the same and this is the main cause of alternative injection inhibiting profile reverse and increasing injection volume in low permeability zone so as to improve oil displacement effect. When alternative injection was applied in pilot tests of Daqing Oilfield, oil production is increased, while water cut increasing rate and polymer powder dosage are decreased. Application result shows that alternative injection is a new injection type of polymer flooding and is a effective measure to increase oil displacement efficiency and reduce polymer dosage.
Low Salinity Waterflooding in Low Permeability Sandstone: Coreflood Experiments and Interpretation by Thermodynamics and Simulation
Authors: Xie Quan , Ma Desheng , Wu Jiazhong , Liu Qingjie , Jia Ninghong , Luo Manli
Published: August 2015

In recent years, low salinity waterflooding (LSWF) has been a promising technique to recover oil in sandstone reservoirs. In view of research results for the last decade, it is acknowledged that substantial oil recovery beyond conventional waterflooding from sandstone is wettability alteration. However, the major contributor to wettability alteration is still uncertain. Therefore, this paper investigates this major mechanism and shows how it is involved in the process of IOR.

Rock and oil surface chemistry were tested to explain the influence of zeta potential on the disjoining pressure. Coreflood experiments with permeability less than 1mD were carried out and the impact of different wettabilities ranging from strong water-wet to slight water-wet on LSWF recovery was investigated with combination of thermodynamic theory. Relative permeability curves were obtained by history matching the corefloods experiments for both slight water-wet and strong water-wet cores with consideration of salinity effect. Thermodynamics of wettability by low salinity waterflooding was analyzed to characterize the surface forces between the surfaces of oil/water and water/rock.

Zeta potential results showed that decreasing divalent cations and salinity makes the electrical charges at both oil/brine and brine/rock interfaces become strongly negative, which results in elevation of the repulsive forces between oil and rock, and as a result the rock turns more water-wet, which was confirmed by thermodynamics characterization. Corefloods experiments showed that a high potential in slight water-wet reservoirs can be achieved by low salinity waterflooding due to the double layer expansion. The relative permeability curves obtained by history matching showed that LSW improves oil recovery by accelerating oil production (relative perm changes) and reducing residual oil saturation in slight water-wet rock but not in strong water-wet rock. Thermodynamics of wettability analysis indicated that the mechanism of low salinity waterflooding might be interpreted by disjoining pressure calculation.

In conclusion, double layer expansion caused by highly negative zeta potential as a result of lower salinity and divalent cation plays a major role in recovering additional oil. The low salinity waterflooding EOR-Effect might be interpreted by disjoining pressure calculation. These findings can help in composition design of low salinity water to maintain higher potential to recover oil in oil field.
Effects of Crude Oil Components on the Interfacial Tension Between Oil and Surfactant Solutions
Authors: Zhu Youyi , Lei Ming
Published: August 2015

The oil/water interfacial tension (IFT) is a key index of the properties of chemical enhanced oil recovery (EOR) displacement systems with surfactant. The studies showed that different oil and water often required different surfactant formulations to reduce IFT. The crude oil compositions in different oilfields differ with each other. Therefore, it requires different surfactant formulations to fit oil properties. It is necessary to reveal what kinds of components in crude oil have crucial influence on IFT reducing ability of surfactants, so as to optimize surfactant formulations for certain crude oil being performed efficiently.

Daqing Oilfield crude oil was cut into five oil fractions with different boiling range by true boiling point distillation method. Group compositions (saturates, aromatics, resins, wax and asphaltene) of high boiling fraction and vacuum residuum were further separated by column chromatography and solvent extraction method. Five oil fractions and seven group compositions of crude oil were obtained. The effects of these fractions and chemical compositions on the performances of surfactants in reducing IFT were investigated.

The IFT for the crude oil fractions and group components separated were tested using sodium alkylbenzene sulfonate (ABS) surfactants with different structures. The results indicated that oil fractions and group components have different impact on surfactants in reducing IFT. Low IFT value could be obtained for 200–350 °C and 350–400 °C oil fractions by ABS with carbon chain length of C16-C18 or C16 alkyl methyl benzene sulfonate. The unfavorable interfacial activity for oil fractions were low and high boiling point fractions. The effect degree order of IFT reducing ability for group components by ABS surfactants was: resins > aromatics > saturates > wax. High boiling point fractions and heavy components of resins and aromatics significantly influence on the performance of ABS surfactants in reducing IFT. Based on these results, an industrial product HABS was developed which could reach ultralow IFT between crude oil and surfactant solutions.

Understanding the effect of crude oil components on the performances of surfactants in reducing oil/water IFT will help us to screen and optimize surfactant oil displacement formulations targeted according to the different properties of crude oils.
Enhanced Foam Stability By Adding Dispersed Particle Gel: A New 3-Phase Foam Study
Authors: zhao Guang , Fang Jichao , Dai Caili , Yan Yuan , Yan Zhihu , You Qing
Published: August 2015

Foam has been successfully used for profile control in mature reservoirs for the advantages of easy preparation, selectively plugging capacity, effective profile control and displacement efficiency capacity. However, the stability of foam is a serious problem for scale applications in oilfields. Due to viscoelasticity, strong shearing stability, high temperature and salinity resistance of micron dispersed particle gel (DPG), it was prepared to stabilize foam.

The micron DPG particles were prepared using bulk gel by high shearing method in our lab (C.L. Dai, et al., 2012). A new three phase foam system was successfully prepared by adding micron DPG particles through a modification of Ross-Mile method. The foaming capacity, stability and morphology were systemically investigated. The plugging capacity and enhanced oil recovery capacity of new three phase foam have been also investigated by sand-pack flowing tests.

The effects of surfactant concentration, DPG particle concentration, salinity, oil concentration and gas-liquid ratio on the foaming capacity of three phase foam are systematically investigated. Increasing in surfactant concentration, DPG particles concentration and gas-liquid ratio can improve the foam volume and decay half-life of three phase foam, whereas increasing in salinity and oil concentration decrease the foam volume and decay half-life. By increasing in solution viscosity, adsorption at gas-liquid interface and non-adsorption in solution, the DPG particles can effectively stabilize new three phase foam. Morphology results show that the formed new three phase foam is compact and uniform. Sand-pack experimental results show that the new three phase foam has a better plugging capacity and enhanced oil recovery capacity than traditional aqueous phase foam. The new three phase foam may have a great potential for profile control in mature reservoirs.
Composition Characteristic and Miscibility Behavior of Continental Deposit Reservoir Oil
Authors: Ke Zhang , Li Shi , Ma Desheng , Chen Xinglong
Published: August 2015

One of the key factors in the design of gas injection project is the minimum miscibility pressure (MMP) because local sweep efficiency from gas injection is mainly dependent on the MMP. Slim tube displacement, vanishing interfacial tension, and rising bubble method are three main tests to determine MMP. However these tests are both expensive and time consuming. Our study aims to find a quick and accurate mathematical methodology to determine gas–oil MMP. This study was conducted using 30 wells data sets which have experimental CO2-MMP values. These data sets were corresponding to gas/oil compositional information of 25 blocks. In order to understand miscibility mechanism between CO2 and oil, mass transfer phenomenon between them was firstly displayed in a visible pressure-volume-temperature (PVT) cell apparatus. Different hydrocarbon compositions range effecting on miscibility were presented and reservoir oil components are classified into three pseudo-components for modeling process, which are C2-C15, C1+N2+C16+ and colloid-bitumen. Finally, CO2 density under reservoir temperature, composition coefficient (Xf) and colloid-bitumen content (mass percent) were used to predict pure CO2 MMP, a model with 3 variables was developed. The results of proposed model agree well with experimental data, which indicates that the model was reliable and predictive. This study shows great possibility for future enriched CO2 miscible injection to improve miscibility and enhance oil recovery.
Discerning In-Situ Performance of an EOR Agent In the Midst of Geological Uncertainty: II. Fluvial-Deposit Reservoir
Authors: Fatemi S. A. , Jansen J. D. , Rossen W. R.
Published: August 2015

An enhanced-oil-recovery (EOR) pilot test has multiple goals, among them to make money (if possible), demonstrate oil recovery, verify the properties of the EOR agent in situ, and provide the information needed for scale-up to an economic process. Given the complexity of EOR processes and the inherent uncertainty in the reservoir description, it is a challenge to discern the properties of the EOR agent in situ in the midst of geological uncertainty. We propose the “modified Egg Model” case study to illustrate this challenge: a polymer EOR process designed for a 3D fluvial-deposit water-oil reservoir. The polymer is designed to have a viscosity of 20 cp in situ. We start with 100 realizations of this 3D reservoir to reflect the range of possible geological structures honoring the statistics of the initial geological uncertainties. For a population of reservoirs representing reduced geological uncertainty after five years of waterflooding, we select three groups of 10 cases out of 100 with similar water breakthrough dates at the four production wells. We then simulate five years of polymer injection. We allow that the polymer process might fail in situ and viscosity could be half that intended. We test whether the signals of this difference at injection and production wells would be statistically significant in the midst of the geological uncertainty. Specifically, we compare the deviation caused by loss of polymer viscosity to the scatter caused by the geological uncertainty at the 95% confidence level. Among the signals considered, polymer breakthrough time, minimum oil cut and rate of rise in injection pressure with polymer injection give the most reliable indications of whether a polymer viscosity was maintained in situ. Unfortunately, given the likelihood of an unknown extent of fracturing of the injection well, injection pressure may be an unreliable indicator of in situ polymer viscosity.
Characterization of Ultra-High Molecular Weight Oilfield Polyacrylamides Under Different pH Environments Using Asymmetrical Flow FFF and Multi-Angle Light Scattering Detector
Authors: Dalsania Yogesh , Doda Ankit , Trivedi Japan
Published: August 2015

Various types of ultrahigh molar mass polyacrylamides (PAMs) or HPAMs and their co- and ter-polymers used not only in enhanced oil recovery, but also in drilling, fracturing, water treatment and tailing applications require an accurate description of polymer molar mass (Mw) and hydrodynamic size for their optimal design. The range of Mw for various types of available HPAMs is between 4 and 30 million g/mol and is typically determined using intrinsic viscosity measurement.

Molecular weight distribution (MWD or PDI) cannot be determined since neither standards with low PDI nor GPC/SEC techniques exist today for such ultrahigh molar mass polymers. Moreover, the solution environment in underground reservoirs, characterized by high temperatures, pH and the presence of monovalent and divalent ions, may often lead to changes in polymer macromolecular conformation. Current techniques, such as light scattering or microscopy, SEC, ultraviolet visible measurements and liquid chromatography, are not capable of accurately investigating these macromolecular complex structures for various reasons. In this paper the Asymmetrical Flow Field Flow Fractionation system was utilized to fractionate four different ultrahigh molecular weight HPAM samples, varying in molar mass and commercially used for oilfield applications, in different carrier pH values ranging from 12 to 3 (pH 12, pH 7.4 and pH 3). The system uses field flow fractionation a family of analytical techniques developed specifically for separating and characterizing macromolecules, colloids and particles. Other advantages over conventional GPC/SEC include minimum shear degradation, mild operating conditions and no sample loss due to adsorption. The flow system was equipped with a multiangle light scattering and refractive index detectors to measure molar mass and radius of gyration.

The results show that the samples molecular weights increased substantially as the pH (or the ionic strength) of the carrier solution decreased from 12 to 3, especially for higher molar mass polymers. The samples radius of gyrations showed the opposite trend decreasing as the pH of the carrier solution changed from basic to acidic. For ultrahigh molecular HPAM at high pH, a narrower molar mass and radius distribution was observed with disaggregated molar mass and increased branching or swelling (therefore higher hydrodynamic radius). Use of this direct separation and measurement technique can improve understanding of polymer macromolecular structure and respective changes in the reservoir environments to enable optimal chemical dosage in oilfield applications.
Estimation of Polymer Retention from Extended Injectivity Test
Authors: Juri J. E. , Ruiz A. M. , Hernandez M. I. , Kaminszczik S..
Published: August 2015

The aim of this study was to reduce risk in polymer flooding projects. Specifically, this study investigates polymer retention and viscosity losses. The study reservoir is a fluvial type reservoir with friable/unconsolidated sandstone units that are saturated with viscous oil. The reservoir is located in the south of Argentina. Retention and viscosity losses are the key parameters in designing a polymer flooding. They slow down the polymer velocity and deplete the polymer slug leading to a significant impact in the oil banking formation and therefore in the oil response. In friable/unconsolidated reservoir rock samples the usual laboratory procedure for retention estimation is fraught with complications and errors and may lead to unreliable results.

We used a 20 month single-well injection/back-production test. And we monitored the sweep efficiency with time-lapse formation resistivity logging. The well schedule included, 5 months of water injection, three months of polymer injection and 12 months of back-production. We used an innovative inline viscometer to measure viscosity in the backflow stream at anaerobic conditions. This procedure avoided the problems of chemical degradation due Fenton chemistry with the oxygen scavenger. We measured the concentration with two methods, COD (Chemical Oxygen Demand) and bleach method.

The back-produced polymer solution showed relatively low viscosity losses as compared to that of the injected solution. The interpretation of the polymer concentration measurements with a detailed simulation model led to retention bounds between 35 to 260 micro-grams of polymer per gram of rock with heterogeneous retention depending on the facies.

This is sevenfold the value estimated from packs of crushed reservoir core material and threefold the value from coreflood studies in reservoir samples. This study has allowed us to adjust the forward planning and understand the retention behaviors in distributed clay fluvial formations.

This methodology can provide low cost reliable estimations of polymer retention at a larger scale than corefloods.
Foam Simulation From Coreflood to Field Scale
Authors: Masoudi Rahim , Ann Giddins Marie , Karkooti Hooman , Jalan Shlok , Valero Gil Adelis Alfonzo
Published: August 2015

Although there is a wealth of literature on experimental studies and theories of foam behavior, industry experience of foam enhanced oil recovery is still limited, and it remains a challenge to move from laboratory studies to field scale predictive simulations. This work describes a reservoir simulation study of foam enhanced oil recovery (EOR) processes, starting from a matched coreflood experiment, and extending the model to investigate foam behavior at a larger scale and over longer times.

A core-scale compositional simulation model is constructed, including chemical reactions to represent foam generation, adsorption and decay over time, with a functional representation of gas mobility reduction due to foam behavior. The simulation parameters are tuned to match production and pressure for a laboratory coreflood consisting of water, gas, surfactant and Surfactant-Alternating-Gas (SAG) injection phases. The core is modeled with 2D and 3D grids at coarse and fine scales and the results are extended to field scale sector models. Sensitivity runs are performed to determine the impact of key parameters on foam behavior for different model resolutions, sizes and timescales.

The impact of gravity override, heterogeneity, adsorption and decay can be observed even in core-sized models, and visualization of the simulated results over time shows the effect of grid design in capturing foam behavior in the core. At the field scale, simulations demonstrate qualitatively how foam improves oil recovery by reducing gas mobility and delaying breakthrough. However, upscaling and numerical dispersion effects can be significant when modeling chemical reactions and foam physics. The complexity and uncertainties of foam processes mean that additional measured data from experiments and pilot projects are needed, to develop confidence in predictions of field performance.

In this work, we aim to fill some of the knowledge gaps in simulation of foam EOR, by describing practical approaches for modeling and understanding foam processes at different scales. We focus on important parameters for upscaling from experimental results and make recommendations for further studies to assist with de-risking foam EOR projects.
Insights for Air Injection EOR from Static Oxidization Behaviours of Crude Oil
Authors: Wei Xiaofang , Yang Siyu , Wang Bojun , Yang Yongzhi , Song Wenfeng , Xu Ying , Zhou Minghui , Liu Keyu
Published: August 2015

Laboratory simulation experiments of air injection with low temperature (65°C, 17 MPa) for a low permeability (4.5 mD) reservoir was conducted by using crude oil from the Dagang Oilfield, Northern China. The initial oil density and viscosity are 12 API and 74.5 mPa.s, respectively. The physical properties of the crude oil such as viscosity, density in the oxidation zone before and after air injection were measured. Changes of both the saturated hydrocarbons and aromatic fractions were analyzed using GC X GC-FID. The changes of resin, asphaltene and oxygenated products were analyzed using a Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS).

The results indicate that the produced CO, CO2 and the gasified low molecular weight hydrocarbons drive the oil out from the tight reservoir core with an oil recovery of 45 %. The viscosity of the produced oil is reduced slightly by 2.6 %. The in situ viscosity, although not measured directly, should have been reduced significantly due to the thermal effect. The physical properties of the oil in the oxidation zone are deteriorated significantly, with the viscosity being increased by 30 % and the content of Oxygen by 7 %.The oxidization pathways from molecular alterations based the static oxidization of light oil at low temperature are also explored in accordance with the molecular heterogeneities.
Development of Thermo-Gels for in Depth Conformance Control
Authors: Al-Maamari R. S. , Al-Hashami A. R. , Al-Sharji H. H. , Dupuis G.. , Bouillot J.. , Templier A.. , Zaitoun A..
Published: August 2015

A novel technology has been developed for in-depth profile control based on thermo-gelling polymers (refers as THR). This technology differs from the ones currently used through different aspects. Thermo-gels polymers spontaneously gel when they reach a threshold temperature. Below this temperature, the product behaves as low-viscosity fluid, with good injectivity in reservoir rock. The system is single-component, and does not require any additive, contrary to classical gel systems which need to mix a polymer with a cross-linker (and often additives) to control gelation time. It is thus of easy control and does not face the drawbacks of two- or multi-component gel systems. Moreover this family of products is bio-sourced, thus environmentally friendly (some are CEFAS approved). Different THRs have been developed whose gel temperature varies between 25 and 85°C.

The present work details laboratory evaluation of different THRs, including rheological properties, gel kinetics, gel strength, long-term stability and coreflood experiments.

Main results are as follows: i) gel temperature can be optimized by varying brine salinity and THR type and/or concentration; ii) gel kinetics is very rapid once the gel temperature is reached, iii) THRs remain stable over period of time superior to one year in reservoir conditions; iv) coreflooding experiments in sandstone rocks show moderate adsorption (around 50 μg/g), good injectivity below gel temperature and strong pressure build-up once gel temperature is reached. Gel strength can be as high as 35 bar/m.
Minimizing Formation Damage for Preformed Particle Gels in Mature Reservoirs
Authors: Elsharafi Mahmoud , Bai Baojun
Published: August 2015

In oilfild operations, it is important to decrease water production and increase the efficiency of oil sweep. A gel treatment is using preformed particle gels (PPGs) to reduce water flow through high-permeability formation in mature reservoirs. The success of PPGs treatment primarily depends on whether or not PPGs can reduce the high permeability zones to the anticipate level. This work sought to find methods that minimized the damage caused by PPGs on unswept, low-permeable zones/areas, thus improving PPG treatment efficiency. These results can help to identify of the best PPG types, particle sizes, and brine concentrations for specific reservoir condition. Both a static filtration test model and load pressure model were used to evaluate the damage caused by various PPGs on sandstone core samples with various degrees of permeability. Two types of particle gels, a strong Daqing gel (DQ) and a weak LiquiblockTM 40k gel (40K), were used for various experiments, each with a different strength. The particle sizes ranged from 30 to 120 meshes. Sodium chloride (NaCl) was used to prepare all brines. Various brine concentrations at room temperature were selected to prepare the swollen PPGs. The effect of particle size, core permeability, and brine concentration on core damage was investigated. Results of these experiments yielded information useful for promoting the best PPG treatment for conformance control in mature reservoirs. These results can be used to optimize PPG's design and, thus, prevent damage to the unswept, low-permeable zones/areas.
Novel Visualisation of Chemical EOR Flooding Using a Lab-on-a-Chip Setup Supported by an Extensive Rheological Characterisation
Authors: Wegner J.. , Hincapie R. E. , Födisch H.. , Ganzer L..
Published: August 2015

Two phase polymer flooding experiments were carried out using a novel Lab-on-a-Chip experimental set up. The microfluidics device uses porous Glass-Silicon-Glass (GSG) micro-models which were constructed based on reservoir rock thin section. The model attempts to resemble the thin sections internal porous structure geometry but also the rock wettability. The results were monitored and analyzed in real time using an image analysis algorithm.

Polymer flooding is widely used to obtain incremental oil recoveries through providing favorable mobility ratio. However, its ability to mobilize and displace oil at microscale through its viscoelastic properties is still debated. EOR flooding experiments performed in micromodels that resemble porous media provides continuous visual access that combined with quantitative image analysis can provide improved understanding on displacement mechanisms. In particular, the more difficult questions concerning the complex viscoelastic behavior of polymers and its role in mobilizing trapped oil. In addition, when verified, micromodel based flooding can provide a complement to experimentation on limited core samples.

The experimental results did not show a significant increase in oil recovery due to viscoelasticity in the micromodels used at the preset experimental conditions. GSG micromodels were successfully implemented under reservoir temperature for flooding experiments. Additionally it was found that using an extended Cox-Merz Plot (relation between Rheological parameters) to describe the rheology will improve the interpretation of the phenomena taking place; as well as considering the elongational rheology of aqueous polymer solutions.

The results presented in this work show that flooding experiments in micromodels have a great potential to improve chemical EOR screening processes. The visualization technology depeloped during this work will contribute significantly and can be the enabler of intensified application of microfluidics technologies in EOR.
Visualization of In situ Microemulsion Phase
Authors: Unsal E.. , Broens M.. , Buijse M.. , Boersma D.. , Makurat A.. , Armstrong Ryan T.
Published: August 2015

In situ formation of microemulsions is studied by co-injection of its individual phases: surfactant solution and decane oil. The experiments were conducted in micro-channels etched on a glass micromodel which facilitates the direct observation of the microemulsion formation. The micromodel was horizontally placed under an inverted fluorescence microscope. The aqueous phase was injected via one micro-channel and the oil phase was injected via another. The two microchannels merged at a T-junction where the microemulsion phase started forming upon mixing of its two individual phases. The oil phase was doped with an oil-soluble fluorescent dye, called Nile Red, which shifts its fluorescent peak based on the polarity of the environment. Under fluorescent light, the microemulsion and oil phase fluoresced bright red and amber brown, respectively.

Microemulsions found their application in chemical enhanced oil recovery (cEOR) due to their ability to eliminate the capillary forces by generating ultra-low interfacial tension (IFT) between the aqueous phase and the oil-in-place. The flow regime shifts from immiscible to a quasi-miscible one, allowing the brine to access the more isolated parts of the rock. Inevitably the microemulsion becomes part of the flowing system and it has to be recovered. Therefore understanding of the microemulsion rheology as well as its IFT is important. The common knowledge on microemulsion formation is limited to the phase behavior analysis performed in static test tubes. Such tests answer some questions on microemulsion properties once they are formed, but they do not provide any insight to how a microemulsion forms and flows.

This study presents a methodology to visualize the microemulsion together with its aqueous and oil phase components at the time scale necessary to study mixing. These visualizations can provide insights into questions regarding in situ microemulsion formation, and consequently, the rheological behavior of multiphase systems with ultra-low IFT. Our experiments indicated that at flowing conditions the fluids may mix spontaneously, and the mixing profile depends on the salinity of the environment as well as the injection rates.