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IOR 2017 - 19th European Symposium on Improved Oil Recovery
- Conference date: April 24-27, 2017
- Location: Stavanger, Norway
- Published: 24 April 2017
21 - 40 of 139 results
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Supramolecular Assemblies as Displacement Fluids in EOR
SummaryThe concept is that the viscosity of injected supramolecular system will be maintained at initially low values for easy injection and pumping, and then increased by means of an external pH stimulus just before or upon contacting oil. Our promising lab-scale preliminary studies have indicated that such supramolecular systems possess not only reversible pH-responsive properties but also very tolerant against high salinities and temperatures.
Supramolecular solutions can adapt to the confining environment. For instance, when a height molecular weight polymer macromolecules are forced to flow into narrow channels and pores, molecular scission processes may take place.
Supramolecular solutions can have significant impact on the cases where thermal methods cannot be used for some viscous oils due to thin zones, permafrost conditions and environmental constraints. This project is primarily aimed at developing novel supramolecular assemblies with adjustable viscosity and interfacial properties that have robust tolerance against high temperatures and salinities. Such supramolecular assemblies will be used to significantly improve the feasibility and cost-effectiveness of displacement fluids used in EOR. Overall, there is a significant potential for application of supramolecular solutions in the US and throughout the world.
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Nanoemulsion Flooding - The Journey to Field Begins
Authors E. Braccalenti, L. Del Gaudio, P. Albonico, A. Belloni, M. Bartosek and E. RadaelliThe continuous and growing request of energy worldwide, together with the depletion of the oil and gas resources, lead to an increasing interest to develop and apply EOR techniques in order to improve the production of already exploited reservoirs. In this scenario, current chemical EOR technologies are not yet widely applied, mainly for the high costs associated and high volumes required. “New” technologies and renovated chemical approaches must be implemented in order to make the chemical EOR processes extensively used. Among them, Nanotechnology seems to have an extraordinary potential to change production processes.
Taking into account encouraging results recently achieved at laboratory scale using Nanoemulsions and aspiring to the field, the aim of this study was dual: on one hand render nanoemulsions cost effective and attractive for field applications, on the other hand, have a deeper understanding and knowledge of nanoemulsions mechanism of action and effect of on porous media.
The two goals have been pursued with an intense formulative work based on a particular “low energy” proprietary method and using both bulk fluid characterizations and core floodings. Particular attention has been reserved to effluents observation and characterization in order to reveal criticalities associated to the application of this technology.
A possible key role of the coexistence, in nanoemulsions, of small droplets size, surfactants mixture and solvent has been highlighted. In fact, these actors can favorably impact, in a synergic way, some critical parameters associated to oil recovery such as oil/water interfacial tension, wettability and oil viscosity. Surfactant adsorption/retention as well as rock/nanoemulsion interactions have been also evaluated.
The future applicability of nanoemulsion strongly depends on its costs that can be reduced decreasing the amount of surfactants and solvent present in the formulation. This surely has an impact on nanoemulsion intrinsic structure (i.e. average droplet size, surface area) but not necessarily on the efficiency of mobilization of residual oil in porous media. Furthermore, alternative injection approaches can induce additional savings.
The next phase foresees studies on injection strategies, the design of an up-scaled nanoemulsion production and nanoemulsion tuning on the basis of specific field parameters in order to render the technology suitable for a SWCTT.
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A Novel Optimization of SAGD to Enhance Oil Recovery - The Effects of Pressure Difference
More LessSummarySteam-Assisted Gravity Drainage (SAGD) provides many advantages compared to alternate thermal recovery methods for bitumen recovery. Nowadays, most of researchers believe that the gravity mechanism is the main drive in SAGD recovery, ignoring the injector-producer pressure difference, which makes the field prediction deviate from reality. To tackle this problem, this paper makes further investigation on the injector-producer pressure difference. A series of 2D numerical simulations are conducted on the basis of Mackay River reservoir in Canada to investigate on influence of injector-producer pressure difference. Meanwhile, a new mathematical model considering injector-producer pressure difference is established. The results indicate that when the injector-producer pressure difference exists, SAGD usually has better recovery. Pressure difference can effectively improve SAGD operating performance to achieve a high economic efficiency. More pressure difference doesn’t necessarily lead to better recovery, for when the pressure difference increases to some certain degrees, it will cause steam breakthrough. Pressure difference usually plays an important role at the beginning of SAGD recovery, therefore it is better for us to increase pressure difference at the steam rising stage and decrease pressure difference at the steam chamber expansion to avoid steam breakthrough, and finally to achieve a high economic efficiency.
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Laboratory Testing of Thermo-chemical Schemes for Carbonate Heavy Oil Reservoirs
Authors S. Ursegov and E. TaraskinSummaryThe objective of this work is the Permian - Carboniferous reservoir of the Usinsk field located in the Timan-Pechora province of Northwest European Russia. The oil-producing rocks are the naturally fractured limestones and dolomites. The live oil viscosity is equal to 1240 mPa*s. In the reservoir, there is a steam injection at ~300°C and ~10 MPa. The current oil recovery numbers are estimated between 8 – 10 %. These oil recovery efficiencies could be improved with the injection of suitable chemicals to increase the water wettability of the reservoir matrix. In order to justify a package of measures aimed to increase the reservoir oil recovery factor, special laboratory studies were carried out with the help of hot water and steam injection thrown the stacked models of full-sized and standard-sized core samples. In addition, the experiments of heavy oil extraction by hot water in combination with surfactants were conducted. This work summarizes the results obtained during the laboratory tests. The combined use of hot water and the NOP surfactant increases the oil recovery factor up to 38 %. However, the oil-wet characteristic of the reservoir rocks did not modified even upon their heating up to the temperatures of 100 – 2500C.
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Overcome Viscous Fingering Effect in Heavy Oil Reservoirs by an Optimized Smart Water Injection Scheme Part II
Authors T. Kadeethum, H.K. Sarma, B.B. Maini and C. JaruwattanasakulSummaryViscous fingering is a major obstacle to successful waterflooding in heavy oil reservoirs, as it results in premature water breakthrough resulting in bypassed oil and an underdeveloped oil bank ahead. To reduce viscous fingering, the composition of injected fluid needs to be tailored to create a favorable mobility ratio with the oil to be displaced. Smart waterflooding often entails wettability alteration in the reservoir, and it can also lead to a change in mobility ratio, which depending on the value, may have either a negative or positive impact on oil recovery.
This study is an extended study from Kadeethum et al. (2017a) because in that paper only one static realization was analyzed. This practice may lead to a bias and unreliable result because we did not include the uncertainties into the system. Therefore, a statistical analysis is used to reveal the smart waterflooding true potential. In this study, smart waterflooding outperforms conventional waterflooding regarding oil recovery, with incremental recovery reaching as high as five percent. Moreover, smart waterflooding also significantly decelerates the water cut (WCUT) trend by subduing the effect of viscous fingering and decreasing the water relative permeability.
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Sedimentary Characteristics and Architecture of Fan Delta Front Reservoir Based on Dense Well Pattern in Oilfield, China
More LessSummaryThe study focus on a Paleogene sandstone reservoir in the northeastern China deposited on a fan delta front, which started to produce since 1986. Through long term of steam huff-puff, the average reservoir pressure declines from 9.75Mpa to 2Mpa, the water cut increases to 90%. Therefore, a steam driving pilot with 417 wells is built, and the detailed sedimentary analysis and reservoir architecture characterization is urgently needed to better understand the distribution and connectivity of reservoir. The study is based on the analysis of 6 core data, 417 well logging data and several surveillance data, such as injection profile and tracer. The reservoir architecture in single well, plane and profile of main producing layers is depicted, the architecture modes is established with the analysis of connectivity and forming environment, the scale of different architecture elements is summarized, and the effect of architecture on reservoir performance is analyzed by using surveillance data for further development adjustment proposal.
There are 14 lithofacies identified in the study area, which can be classified into five architecture elements: underwater distributary channel, mouth bar, underwater distributary inter-channel sand, underwater distributary inter-channel mud and sheet sand. Three types of lateral architecture modes, five types of vertical architecture modes, and three types of plane combination modes of architecture elements are established, with detailed discussion of pattern, cross section, plane distribution, genetic mechanism and connectivity. The scale of distributary channel and mouth bar in different architecture modes is summarized and compared. Finally, further development adjustment plan is proposed according to the effect of architecture on reservoir performance, such as the producing layer with isolated banding distributary channels is suggested to perform stratified gas injection, the injection and producing well should be placed in layers with good connectivity, like sheet-shaped distributary channels etc.
The study provides a comprehensive case study for geologists and engineers to better understand the sedimentary characteristics and architecture of fan delta front reservoir, which help to provide fine-scaled geological model and adjust development plan for improving recovery.
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A Non-standard Model for Microbial Enhanced Oil Recovery Including the Oil-water Interfacial Area
Authors D. Landa-Marbán, F.A. Radu and J.M. NordbottenSummaryIn this work we present a non-standard model for microbial enhanced oil recovery including the oil-water interfacial area. Including the interfacial area in the model, we eliminate the hysteresis in the capillary pressure relationship. One of the characteristics that a surfactant should have, it is biological production at the oil-water interface. Therefore, we consider the production rate of surfactants not only as a function of the nutrient concentration, but also the interfacial area. To solve the model equations, we use an efficient and robust linearization scheme that considers a linear approximation of the capillary pressure gradient. A comprehensive, 1D implementation based on two-point flux approximation of the model is achieved. We consider different parameterizations for the interfacial tension and residual oil saturation reduction.
Illustrative numerical simulations are presented, where we study the spatial distribution and evolution in time of the average pressure, water saturation, interfacial area, capillary pressure, residual oil saturation and bacterial, nutrient and surfactant concentrations. Inclusion of the interfacial area in the model leads to different predictions of oil recovery. The model can also be used to design new experiments contributing to a better understanding and optimization of MEOR.
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EOR Screening and Potential Applications on the Norwegian Continental Shelf (NCS)
Authors J. Zuta and A. StavlandSummaryEnhanced oil recovery (EOR) projects have moved down the industry’s priority list given the present oversupply of world crude oil and resulting low oil prices. However, this is the right time for the industry to evaluate options for injecting new life into some of the brown fields on the Norwegian continental shelf (NCS). Inspite of the current market challenges, EOR application in offshore oil fields remains a promising option for increasing the oil production on the NCS. The size of the targeted offshore oil fields is generally large and their proven original oil in place (OOIP) can be sufficiently large to overcome the high cost required for re-development. This means that a large amount of oil remaining on the NCS could potentially be recovered using EOR processes.
In this work, the main objective was to screen some selected oil fields on NCS for possible EOR processes based on present-day reservoir data. The work was carried out in the National IOR Center based on published reservoir data on the selected fields. As a result, available reservoir information for the selected fields were limited. In addition, there were significant differences in the quality of field data supporting the viability of the various EOR processes considered. However, a fast evaluation of various EOR processes based on a simulation screening tool, SWORD proved to be very useful and assisted in providing an assessment of recovery strategies and EOR methods applicable for the selected fields.
The EOR processes screened included hydrocarbon gas, CO2, surfactant, polymer and a combined surfactant/polymer process. The screening criteria for the EOR processes were based on six quantitative reservoir data namely density and viscosity of reservoir oil, and properties such as depth, temperature, porosity and permeability of the formations. The applicability of the different EOR methods and recovery strategies at different reservoir properties and conditions were evaluated based on existing information published on the selected fields and knowledge collected from a suite of successful EOR projects around the world.
Results based on simulations indicate that the estimates of potential EOR incremental oil recovery compared to water flooding for the screened fields can be quite significant. However, key project development including realistic laboratory experiments and reservoir simulations needs to be performed to evaluate the EOR processes in detail. In addition, implementation and environmental issues, and additional cost elements must be weighed equally with oil recovery forecasts in any EOR ranking process.
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Bugs and Electric Fields - Underexplored IOR?
By J.N. RavnåsSummaryElectric and magnetic fields can influence microbial activity and could be used to control and improve the efficiency of microbial enhanced oil recovery. In addition, large electric and magnetic fields could be useful in improving operational efficiency by preventing undesired microbial processes in the petroleum industry. This paper reviews the literature from outside this industry to demonstrate that electric and magnetic fields can alter microbial activity. As expected very high fields deactivate or kill microbes but, perhaps unexpectedly, modest fields can actually increase their activity and also help to direct their movement.
Microbes may be affected by electric and magnetic fields in three ways: 1) Membrane permeabilization that can induce either inactivity or activity, 2) Cell orientation alteration, 3) Cell velocity changes.
Ways in which pulsed electric fields can be modified to influence microbial behaviour include: change field intensity, number of pulses, pulse width and pulse shape. The critical field when membrane permeabilization occurs seems to depend on cell size, orientation and type of cell wall.
This paper gives background material that, through research, may lead to future oil industry applications using electrical and magnetic fields to control microbial behaviour.
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Evaluation of Three Large Scale ASP Flooding Field Test
More LessSummaryScaling, emulsion breaking and high cost prevent ASP flooding going laboratory to field. When anti-scaling and produced fluid disposal challenges has been gradually solved in China after years of hard work, the sharp drop oil price makes prospect of ASP flooding dim again. However, ASP flooding is still very promising and has entered into commercial application in 2014 in Daqing. In 2015, the whole crude production from ASP flooding in Daqing was 3.509 million ton, 9.14% of the total production of Daqing oilfield (38.386 million ton). In 2016, there are more than 22 ASP flooding field projects active in Daqing, and the total ASP flooding oil production is 4.06 million ton, 11.11% of total oil production in Daqing. One of the three evaluated ASP flooding tests, ASP 1,2,3, is weak alkali (Na2CO3) based, the other two are both strong alkali (NaOH) based. These three tests shared four slug formulation, which is current standard practice in Daqing. Surfactants and polymers are all domestic. The total cost consists of construction investment, injected chemical fees (polymer, surfactant and alkali), operation fees including maintenance and repair fees, and water disposal fees. These costs are actual spending during ASP flooding tests. Though the ASP 1 and ASP 2 have the similar incremental oil recovery (30%) and both successful, the economic performances of weak alkali ASP flooding is much better for lower commuted total cost. Total cost of ASP 1 and ASP 2 is 28.2 $/bbl and 36.3 $/bbl respectively. The reservoir formation of ASP 1 and ASP 2 has many similarity, thus the difference can reflect alkali effects. ASP 3 has incremental oil recovery of 20.5% upon waterflooding, while it has much higher cost (49.5 $/bbl) than ASP 1 and ASP 2. This is attributed to the much higher polymer molecular and concentration injected, but less oil production. Though higher viscosity helps to overcome the severer heterogeneity as expected, it actually blocked the relative lower permeability formation. This tests shows that formation contamination is important issue to be considered. In high oil price era, the incremental oil recover can be regarded as core parameter since the cost increase can always be compensated by benefits of more oil, while in ultra-low oil price era, the balance between input and output is vital. Previous large scale ASP flooding field tests and current ASP flooding in practice shows that ASP flooding is still very promising even under such low oil price.
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Comparison of Scaling in Strong Alkali and Weak Alkali ASP Flooding Pilot Tests
Authors H. Guo, Y. Q. Li, Y. Zhu, F. Y. Wang, D. B. Kong and R. C. MaSummaryScaling was proven great challenge to prevent ASP flooding going from laboratory to field especially in low oil price era. Both strong alkali ASP flooding (SASP) and weak alkali ASP flooding(WASP) tests were compared from perspective of scaling to help understand ASP technique. ASP field tests in Daqing indicated that scaling(Na2CO3) due to strong alkali(NaOH)was much more severe than weak alkali, which reflected by more pump stuck, higher pump checking rate and short pump checking time.Scaling type in WASP was different from SASP and the percentage of silicate scale difference distinguished WASP from SASP scale. WASP scaling samples composition was mainly carbonate scale, while a majority of scale from SASP composition was carbonate and silicate, and the proportion of silicate varied with injection stages. Different from WASP, SASP scaling included scaling and formation damage, thus it had greater influence on oil production in SASP than WASP. Scaling mechanism was different between WASP and SASP. Compared with SASP, WASP supersaturation was much lower and this made it uneasy to form new mineral particle. PH value was crucial to scale type. Different ASP blocks proved similar scale type at the same PH value, and as PH value increased, silicate scale content decreased.
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Efficient Brownfield Optimization of a Reservoir in West Siberia
Authors O. Ushmaev, V. Babin, N. Glavnov, R.R. Yaubatyrov, D. Echeverria Ciaurri, M. Golitsyna, A. Pozdneev and A. SemenikhinSummaryIn this work we present a methodology for optimal management of brownfields that is illustrated on a real field. The approach does not depend on the particular reservoir flow simulator used although streamline-derived information is leveraged to accelerate the optimization. The method allows one to include (nonlinear) constraints (e.g., recovery factor larger than a given baseline value), which are very often challenging to address with optimization tools.
We rely on robust (derivative-free) optimization combined with the filter method for nonlinear constraints. It should be noted that the approach yields not only a feasible optimized solution but also a set of alternative infeasible solutions that could be considered in case the constraints can be relaxed. The whole procedure is accelerated using streamline-derived information. Performance in terms of wall-clock time can be improved further if distributed-computing resources are available (the method is amenable to parallel implementation).
The methodology is showcased using a real field in West Siberia where net present value (NPV) is maximized subject to a constraint for the recovery factor (RF). The optimization variables represent a discrete time series for well bottomhole pressure over a fraction of the production time frame. An increase in NPV of 7.9% is obtained with respect to an existing baseline. The optimization methods studied include local optimization algorithms (e.g., Generalized Pattern Search) and global search procedures (e.g., Particle Swarm Optimization). We provide solutions with different levels of approximation and computational efficiency. Without the acceleration achieved through streamline-derived information, the method, while effective, could be prohibitive in many practical scenarios. It is worthwhile noting that part of the solution determined in this work has been tested out on the real field.
Optimal management of brownfields is typically addressed using bottomhole pressure values or rates as well control variables. Well controls given as bottomhole pressure values, although not directly implementable in the real field, are often much easier to put into practice than if they are given as rates. However, optimization algorithms that deal with well rates as control variables can be in many cases computationally faster than methods based on bottomhole pressure values. In this work we combine the two aforementioned desirable features for the optimal management of mature fields: well controls are given as bottomhole pressure values for a more practical implementation, and these values are also determined efficiently using concepts borrowed from optimization via well rates.
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Integration of IOR Research Projects through Generic Case Studies
SummaryThe research project portfolio of The National IOR Centre of Norway includes core scale, mineral-fluid reactions at micron-/nano-scale, pore scale, upscaling and environmental impact, tracer technology, reservoir simulation tools and field scale evaluation and history matching. The complexity of each subtopic and the fact that a multitude of data, scales and disciplines is involved may be an obstacle in proper integration of the research results. For the same reasons, exploiting synergies between the various IOR research projects may be a difficult task. At the same time, a collaborative setup like The National IOR Centre of Norway should enable integrated case studies across scales and disciplines.
In this paper, we investigate the relationships between the different IOR research projects within The National IOR Centre of Norway. An important objective of the presented work is to facilitate integration and motivate research that falls between the typical disciplines and projects involved in an IOR case study. To make the relationships between projects more evident, the projects are described in terms of input and output related to testing, measuring, simulating, monitoring, predicting, and optimizing fluid flow in a reservoir. The ultimate goal of the integrated IOR research is to provide a framework for monitoring, evaluating and understanding the effects of an IOR method tested in a field pilot. The presented work links simulation and history matching of fluid flow, geomechanics and geochemical effects to lab measurements, pore scale and core scale modeling, tracer characteristics, production data and 4D seismic.
As part of the process, two generic case studies are defined, one for a chalk reservoir and one for a sandstone reservoir. The reservoir characteristics are chosen to be representative for fields on the Norwegian Continental Shelf. Two selected IOR methods are discussed; smart water injection and polymer injection.
The paper is a result of a collaborative effort involving researchers from both academia, research institutions and the oil industry.
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Economic Analysis of Profitability Index and Development Cost Based on Improved Oil Recovery (IOR) Projects in Indonesia
SummaryIn early 2016, the oil price has fallen to its lowest level (31.68 US$/bbl) over the last 11 years. Since then, Improved Oil Recovery (IOR) Projects are no longer quite interesting economically for contractors due to the high cost of development.
Until August 2016, there were 407 Field Development Plans approved by the Government of Indonesia and 26 of them are already using IOR methods (waterflood and steamflood). In Indonesia, these methods have been applied in Sumatera and Kalimantan. Currently, the biggest oil recovery is employing the steamflood of the IOR methods, which is operated by Chevron Pacific Indonesia in Sumatera Island since 1981 and it has contributed approximately 40% of the total oil production in Indonesia.
In countries that adopt Production Sharing Contract Fiscal Regime such as Indonesia, there are a number of terms and conditions specifically intended for IOR Projects. To attract and help contractors, they will be given an investment credit and/or interest of cost recovery so that the IOR projects can be developed more economically. Moreover, there are some tools which these contractors may use to improve the economical nature of their projects, such as DMO Holiday, Depreciation Acceleration, Shared First Tranche Petroleum, Split Changes, and many more.
For the purpose of this paper, the geographical areas of Indonesia were divided into 3 different IOR areas (North Sumatera, South Sumatera, Kalimantan). Then, collect the data of the 26 IOR Projects and afterwards the Profitabilty Index and Development Cost were calculated and distributed to those aforementioned areas.
Based on analysis, the results shows that the lowest profitability index is equal to 1.04 while the highest one is 2.28 equal to, meaning that these projects generate positive revenue to the contractors (PI value by > 1). The average development cost of IOR projects in Indonesia is equal to 34.64 US$/bbl, which remain lower than the current oil price. Based on the obtained Profitablity Index and Development Cost above, it can be concluded that the Indonesian IOR Projects are economically acceptable.
Finally, it is expected that this paper will provide contractors with a quick look at the growth of IOR Projects in Indonesia, especially in terms of the analyses of the economical nature required in Indonesia. Moreover, this paper is expected to provide an insight into the flexibility of PSC fiscal regime that can be used to support the economical nature of the IOR projects executed by contractors.
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Wettability Alteration and Interactions between Silicon Dioxide (SiO2) Nanoparticles and Reservoir Minerals in Standard Cores Mimicking Hebron Field Conditions for Enhanced Oil Recovery
Authors D. Sivira Ortega, H. Kim and L. JamesSummaryEconomically suitable innovative techniques are becoming a main objective in the oil and gas industry. SiO2 nanoparticle as a water additive for enhanced oil recovery (EOR) has been gaining grounds during the last few years because of its favourable results at laboratory scale; however, application at field is still unknown. A goal of injecting nanofluids is to promote fluid-rock interaction; therefore, determining the level of interaction between the two is a key factor. This research aimed to study interaction between the 0.01, 0.03, and 0.05 wt% SiO2 nanofluids and standard cores through contact angle experiments; scanning electron microscopy (SEM); mineral liberation analysis (MLA); and inductively coupled plasma optical emission spectroscopy (ICP-OES), to predict EOR mechanisms using SiO2 nanofluids in Hebron field. Hebron field is one of the major developments in offshore Newfoundland and Labrador, Canada, with an estimation of 2620 million barrels of oil in place, and an objective to achieve first oil in 2017. Berea and Bandera standard cores were selected to represent the mineralogical compositions of Ben Nevis Formation, which is the most important reservoir with approximately 80% of the Hebron’s crude oil. The SiO2 nanoparticles were dispersed in seawater from offshore Newfoundland, and the oil used was from offshore Newfoundland. The contact angle measurements at Hebron Field temperature and pressure (62 °C and 19.00 MPa) showed that the maximum decrease occurred after 6 hours of aging the core plug in nanofluids at 62 °C. Berea core presented a decrease from 51.4° to 30.2°, and in the case of Bandera rock was from 76.7° to 29.6°. SEM images and MLA revealed the higher the SiO2 nanoparticle concentration, the more nanoparticle adsorption on the rock surfaces after aging in nanofluids. These results are complemented by ICP-OES analysis on the nanofluids, since SiO2 nanoparticle concentrations in the nanofluids decreased after aging. The wettability alteration observed may be caused by the nanoparticles adsorption and interaction of the nanoparticle with the rock surface.
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Cost-effective Seawater Pre-treatment for EOR Development
Authors B. Dørum and A.A. MuminovaSummaryEOR requires specifically treated seawater adjusted with suitable ionic composition for the injection into the reservoir. Field experience shows that pretreatment constitutes cause significant concern at high volume rates during injection. High algae and silt concentrations in feed seawater cause rapid fouling of membranes. Seawater prefiltration imposes challenge due to heavy weight and expensive maintenance. The present study covers historical observations of ocean warming and important mechanisms of membrane fouling due to algal blooming. A modeling data is extracted with Marine Research Institute of Norway. Ecological and hydrodynamic models of Intergovernmental Panel on Climate Change (IPCC) scenario were used to investigate the effects of climate change on the marine ecosystem of the North Sea. Results indicate increasing phytoplankton and temperature trends.
The solution to remove particles and algae is to install parallel pretreatment system, switching between such units to allow frequent cleaning of some while the parallel units are active. This research includes an estimation of acceptable cost and weight values for the pre-filtration system.
Complex knowledge about phytoplankton and silt concentrations fluctuations must be applied towards development of technically and economically efficient solution for seawater filtration in large volumes.
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Enhance Microscopic Sweep Efficiency by Smart Water in Tight and Very Tight Oil Reservoirs Part II
Authors T. Kadeethum, H.K. Sarma, B.B. Maini and C. JaruwattanasakulSummaryImprovement of oil recovery in smart water injection schemes has been shown to be affected by wettability alteration. This process reduces residual oil saturation, which in turn affects the microscopic sweep efficiency and leads to subsequent enhancement of overall waterflood performance ( Willhite, 1986 ). Tight oil reservoirs are often associated with high clay content and significant cation exchange capacity (CEC) values ( Breeuwsma et al., 1986 ). CEC directly influences smart waterflood behavior as it controls ion exchangeability between the solid and aqueous phases, which in turn, regulates the double layer thickness and the wettability of the system ( Nasralla and Nasr-El-Din, 2014 ).
This paper is an extended study from Kadeethum et al. (2017a) in which only one static realization was analyzed. This practice may lead to a bias and unreliable result because we did not include the uncertainties into the system. Therefore, statistical analysis is used to reveal the smart waterflooding’s true potential. Furthermore, an “estimated effect” method is utilized to identify heterogeneity and CEC value effect. Smart waterflooding outperforms conventional waterflooding in both tight and very tight oil reservoirs in terms of oil recovery. Moreover, smart waterflooding also significantly decelerates the water cut (WCUT) trend by subduing the water relative permeability.
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Impact of Salinity and Water Ions on Surface Charge Alteration in Arab D Reservoir Cores at Elevated Temperatures
Authors S.C. Ayirala, S.H. Saleh, S.M. Enezi and A.A. YousefSummarySmartWater flooding through tailoring of injection water salinity and ionic composition is becoming an attractive proposition for improved oil recovery in carbonate reservoirs. Most of the recent studies suggest that surface charge change induced by lower salinity and certain water ions on carbonate surfaces is the main mechanism responsible for favorable wettability alteration, and consequently, higher oil recovery in SmartWater flooding. Unfortunately, these studies determined surface charges based on the electrophoretic mobility (EPM) measurement technique using powdered crushed core samples, which may not reflect the natural conditions existing in the subsurface reservoirs. In this study we used a state-of-the-art experimental technique based on streaming potential measurements to determine surface charge in intact Arab-D reservoir core samples saturated with different brine salinities and individual ion compositions. We also believe that this is the first time such a measurement technique has been used to measure surface charges in reservoir cores at elevated temperatures.
The results indicated a favorable effect of sulfate ions in Arab-D rocks to alter the surface charge to more negative and the reactivity of these ions increased significantly by almost one order of magnitude at higher temperatures. Such a surface charge alteration to an extreme negative obtained upon exposure to injection waters containing sulfates would release the oil droplets from the carbonate surface. Among the positive ions, calcium showed the highest reactivity to shift the surface charge to slightly positive. Both magnesium and sodium ions showed almost similar behavior to change the surface charge toward less negative. In addition, only minor to moderate changes in surface charge were observed with the positive ions when the temperature is increased. The dynamic time-dependent effects on surface charge measured during the displacement of seawater by SmartWater (10 times diluted seawater) in reservoir cores showed an immediate shift in the surface charge from positive to negative. This instantaneous change observed in the surface charge confirms the beneficial effect of SmartWater on wettability alteration. All of these novel findings from this study will provide several major fundamental insights to better understand the dynamic role of surface charge alteration mechanism on oil recovery in SmartWater flooding.
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Laboratory Investigation of Low Salinity Waterflooding using Carbonate Reservoir Rock Samples
Authors T. Uetani, K. Takabayashi, H. Kaido and H. YonebayashiSummaryA laboratory study was performed to evaluate the possibility of performing a low salinity waterflood in an offshore carbonate reservoir using its rock and fluid samples. A series of spontaneous imbibition and core flood tests were conducted and both tests confirmed the incremental oil recoveries when the composition of the injection brine was diluted and modified.
During the core preparation stage, three uncertainties were identified; the core cleaning procedure, the aging time and the reservoir heterogeneity. First, a core is conventionally cleaned with polar solvents. However, a new core cleaning procedure called the “mild cleaning” has been proposed by Austad, which recommends the use of non-polar solvents. In our laboratory studies, the similar core samples were cleaned by the two different techniques and subsequently the spontaneous imbibition test results were compared. It was found that the low salinity effect was confirmed regardless of the core cleaning procedure. Second, the wettability distribution is not clear in this field. To account for this, the core aging time was varied from eight weeks (more oil-wet) to no-aging (more water-wet). The similar cores were aged for different time and subsequently the spontaneous imbibition test results were compared. It was found that the low salinity effect was confirmed regardless of the aging time, although the core samples with longer aging time showed lower oil recoveries. And third, since the reservoir is heterogeneous, the above sensitivity investigations covered a wide range of rock types within the production intervals. It was found that all rock types showed the low salinity effect.
In addition to the above investigations, a number of water recipes were tested. It was found that the sea water performed better than the formation water, while the diluted sea water performed better than the sea water. The effect of sulfate ions was also investigated. Some core plugs showed the low salinity effect when the concentration of the sulfate ion was spiked, while other core plugs did not respond. The effect of sulfate ions therefore, needs to be further investigated in this field.
Based on the results from the zeta-potential and the contact angle measurements, the low salinity effect in this reservoir was considered to be due to a change in the surface-charge and the wettability, which is consistent with the mechanism proposed by Austad. The conclusion of this laboratory study highlighted the possibility of applying the low salinity waterflood in this field.
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Streaming Potential Measurement to Quantify Wetting State of Rocks for Water Based EOR, In-house Novel Setup Experience
Authors M. Rahbar, A. Jafarlou, M. Nejadali, S. Esmaeili, H. Pahlavanzadeh and S. AyatollahiSummaryThe wetting condition of the reservoir rock is the key to the success of any EOR technique and the ultimate oil recovery. Wettability is dictated by the surface chemistry related to the interactions between the fluids and the rock surface which determines the stability of the water film between the rock and the oil phase. Streaming potential measurement is one of the electrokinetic techniques used to determine the average zeta potential of porous rock which can provide reliable information on fluid-rock interaction and wettability state of the rock surface. Streaming potential measurement has recently been introduced in the oil reservoirs applications and there are still significant uncertainties during the measurements and interpretation of streaming potential results. The primary purpose of this work was to establish a setup to measure the streaming potential of porous media and evaluate voltage measurements that could be used at different conditions. Moreover, according to significant differences of reported zeta potential (depending on measurement methods, measurement conditions and nature of minerals), comprehensive investigations were performed on zeta potential measurements of carbonate samples adjacent to the potential determining ions-PDI by streaming potential technique. Streaming potential coupling coefficients have been measured for 60 samples of calcite and quartz sandpack in adjacent to the fluid with different concentration of PDI and in the pH range of 1.5 to 11. The next step was to develop an understanding of the behavior of coupling coefficient under condition of brine salinity and pH to determine the rock fluid interactions and wettability alteration mechanism. To achieve this goal, the measured streaming potential and zeta potential of each test was compared to the results of adhesion test as experimental measurement of wettability and analysis of equilibrium solution. The experimental setup proposed in this study permits accurate measurements of streaming potential without any effect of polarization. The paired-stabilization and the pressure-ramping methods validate the voltage measurements obtained from the setup. The results showed that the wettability is directly and quantitatively affected by streaming potential measurements and the electrical properties interpreted from these measurements can predict wettability alteration mechanisms such as double layer expansion and ion exchange for various fluids. In addition, an accurate empirical expression is proposed for the measured coupling coefficients which predict streaming potential coupling coefficients and zeta potential of quartz sample in the salinity range from 0.0001 M to 5.5 M of NaCl.
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