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IOR 2021
- Conference date: April 19-22, 2021
- Location: Online
- Published: 19 April 2021
21 - 40 of 77 results
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Organic Oil Recovery - Resident Microbial Enhanced Production Pilot in the Scott Field (UKCS)
Authors R. Findlay, A. Bostock, C. Hill, C. Venske and M. CarrollSummaryIntroduction:
CNOOC has been involved in a pilot study to determine the efficacy of Organic Oil Recovery (OOR, a unique form of microbial enhanced oil recovery) as a means of maximising oil recovery from its Scott field. CNOOC’s operated Scott asset came on stream in 1993 and produces crude oil and natural gas from the Scott, Telford and Rochelle fields. Scott is located approximately 188 kilometers northeast of Aberdeen in 142 meters of water.
Methods, Procedures & Process:
Organic Oil Recovery harnesses microbial life already present in an oil-bearing reservoir to improve oil recovery through changes in interfacial tension increasing the oil’s mobility and improving recovery rates and reservoir wettability. These changes could increase recoverable reserves and extend field life through improved oil recovery with negligible topsides modifications. The pilot injection is implemented by injecting a specific nutrient blend directly at the wellhead with ordinary pumping equipment. The well is then shut-in for an incubation period and thereafter returned to production.
Results, Observations & Conclusions:
During initial laboratory testing of two Scott target wells the reservoir showed a diverse and abundant resident ecology which has been proven capable of undergoing the necessary characteristic changes to facilitate enhanced production. A pilot test was completed on well J17 in July 2020 and due to this application, both an ecology and production response has been proven. In addition to this response a drop in H₂S in both the Oil and Gas phase has been observed. The full method of implementation of the pilot test will also be discussed in detail and will include any challenges and/or successes in this area. The initial starting ecology of the wells will be demonstrated and compared to the ecology post-pilot. Additionally, a comparison of production and H₂S figures prior to and post the pilot implementation will be detailed. A correlation will be demonstrated between changes in ecology and an increase in production and a reduction in H₂S.
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Reservoir Simulation of Low Salinity Impact on Polymer Flooding and Evaluation of Electrodialysis Reversal Benefits
Authors U. Umoh, P. Cordelier, M. Bourgeois, O. Garnier, C. Prinet and S. JouenneSummaryThe objective of polymer flooding is to improve macroscopic sweep efficiency and oil recovery by increasing the viscosity of the displacing water thereby decreasing the water/oil mobility ratio. One major parameter that determines polymer flood performance is therefore the in-situ polymer solution viscosity, which is dependent on several factors such as formation temperature, polymer concentration, shear rate and salinity (salt concentration).
Rheological polymer properties such as bulk viscosity variation with polymer concentration for a given water salinity have been derived from laboratory measurements. Generally, a higher solution salinity yields less viscosity for a given polymer concentration. Such relationship between salinity and polymer solution viscosity needs therefore to be implemented in dynamic simulations to consider the mixing effect of different water salinities (injected, connate, aquifer, etc.) in order to obtain representative in-situ polymer viscosities for polymer flood evaluation.
This paper describes the implementation of salt-dependent polymer viscosity functions in reservoir models and the evaluation of simulation results in order to provide answers related to the impact of salinity variations on polymer flood performance. Evaluation of results shows variation of low salinity and polymer flood fronts within the reservoir when a lower salinity (e.g. <1 g/l) viscous solution encounters the in-situ formation water at higher salinity (5 – 15 g/l), and how this leads to improved macroscopic sweep efficiency and oil recovery. Overall, low salinity viscous fluid injection resulted in a higher oil recovery (up to 6% incremental OOIP) given the same polymer concentration, or a similar recovery with lower polymer concentration (up to 50% less polymer consumption).
The above results proved useful in evaluating the business case of using low salinity water (desalting using Electrodialysis Reversal (EDR) technology) for polymer solution preparation. Chemical savings and polymer concentration reduction are the main advantages for a polymer flooding project. Preliminary evaluations show that significant OPEX and CAPEX savings could be achieved by using EDR on an onshore field with moderate reservoir salinity, which is linked to increased operational efficiency and reduction of chemicals consumption.
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Acceleration of Thermodynamic Computations in Fluid Flow Applications
Authors S. Sheth, M. Heidari, K. Neylon and J. BennettSummaryReservoir simulators model the highly nonlinear partial differential equations that represent flows in heterogeneous porous media. The system is made up of conservation equations for each thermodynamic species, flash equilibrium equations and some constraints. With advances in Field Development Planning (FDP) strategies, clients need to model highly complex Improved Oil Recovery processes such as gas re-injection and CO2 injection, which requires multi-component simulation models. The operating range of these simulation models is usually around the mixture critical point and this can be very difficult to simulate due to phase mislabeling and poor nonlinear convergence. We present a Machine Learning (ML) based approach that significantly accelerates such simulation models.
One of the most important physical parameters required in order to simulate complex fluids in the subsurface is the critical temperature (Tcrit). There are advanced iterative methods to compute the critical point such as the algorithm proposed by Heidemann and Khalil (1980) but, because these methods are too expensive, they are usually replaced by cheaper and less accurate methods such as the Li-correlation (Reid and Sherwood (1966)).
In this work we use a ML workflow that is based on two interacting fully connected neural networks, one a classifier and the other a regressor, that are used to replace physical algorithms for single phase labelling and improve the convergence of the simulator. We generate real time compositional training data using a linear mixing rule between the injected and the in-situ fluid compositions that can exhibit temporal evolution. In many complicated scenarios, a physical critical temperature does not exist and the iterative sequence fails to converge. We train the classifier to identify, a-priori, if a sequence of iterations will diverge. The regressor is then trained to predict an accurate value of Tcrit. A framework is developed inside the simulator based on TensorFlow that aids real time machine learning applications.
Applying this ML workflow to real field gas re-injection cases suffering from severe convergence issues has resulted in a 10-fold reduction of the nonlinear iterations in the examples shown in this paper, with the overall run time reduced 2- to 10-fold, thus making complex FDP workflows several times faster. Such models are usually run many times in history matching and optimization workflows, which results in compounded computational savings. The workflow also results in more accurate prediction of the oil in place due to better single phase labelling.
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Polymer Injectivity Learned From 20 Years’ Polymer Flooding Field Practices
Authors [J. Zong, H. Guo], [S. He, K. Song], X. Li, F. Huang, J. Chen, H. Fu, Z. Wang, K. Song and H. GuoSummaryMany people are interested in injecting high-viscosity polymers, the injectivity of polymers remains a challenging issue. Since polymer flooding has been used in Daqing since 1996 commercially, lessons learned can be helpful. When the injected polymer solution’s viscosity is increased 10-60 times compared to that of water, the injectivity was not reduced by the same extent. Several reasons account for this.
First, fractures near injectors were induced and extended toward producers without much attention. This well explains the not so high injection pressure in high-concentration polymer flooding in Daqing. However, this explanation was based on a homogeneity formation assumption, which may hold for thick formation layers. For multi-layers with a high-permeability streak channeling often occurs.
Second, the injected polymer viscosity was reduced due to high shear rate in near injectors regions. A reduction factor of 50% and 30% was reported from back-produced fluids sampling in Daqing and Shengli oilfield respectively. The permeability, the clay content and composition may also play great role in reducing oxidation effect. Polymer type may also affect injectivity.
Third, the flow pattern differs between the lab and field. In many laboratory studies to evaluate polymer resistance factor (RF) or residual resistant factor (RFF), a linear flow is conduced. However, in actual fields, both linear and radical flow happens. The later produced a lower pressure increase than the former. The skin factor can be an important issue.
Finally, due to the heterogeneity, formation parting-pressure varied from place to place. This makes the average injection pressure between injectors not a good indicator. In many field practices, the injection pressure was controlled to be lower than a general formation parting-pressure, actual injection pressure can be either high or lower than actual formation parting-pressure. Besides, uncontrolled pressures can form without being noticed. This also caused significantly problems, such as well casing damage and poor injectivity. In some blocks in Daqing, all wells were damaged in a certain block with much higher injection pressure than water flooding. Survey of overall oilfield pressure indicated that the higher the injection pressure, the higher well casing damage.
The measures such as hydraulic fracturing and acidification widely adopted in Daqing can alleviate the blocking but cannot solve the problems completely. Some field tests were observed Hall plot for polymer very similar to water flooding, indicating that a larger Hall plot with a slope larger than 1 may be reflection of poor polymer injectivity or blockage.
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A study of Residual Oil and Wettability Effects on Polymer Retention
More LessSummaryThe propagation rate of polymer solution through reservoir rock is significantly affected by the magnitude of polymer retention, and consequently, impacting oil recovery and chemical consumption. Therefore polymer retention is a critical parameter for both the numerical prediction and the actual performance of a polymer flood. A clear understanding of the magnitude and influencing factors is still desired for polymer flooding in carbonates.
In this study, we investigate the retention of a sulfonated polyacrylamide polymer in carbonate cores. The impacts of residual oil and wettability on polymer retention are studied by performing coreflooding experiments at reservoir conditions. Representative reservoir fluids and core samples are used for both experiments of single phase displacement and in the presence of residual oil. Two slugs of polymer with KI tracer are injected, and effluent polymer and tracer concentrations are analyzed for determining polymer retentions and inaccessible pore volumes (IPV).
Results show that the retention of the tested polymer in carbonate cores is relatively low, ranging from 26.0 to 60.8 µg/g-rock. In the presence of residual oil the polymer retention has more than 50% reduction. This indicates that the oil in reservoir environment has positive impact on polymer consumption, and the studied polymer has a potential for carbonate reservoir applications. Compared to the significant effect of the oil presence, it was observed that wettability change caused a slight variation in polymer retention results. This suggests that wettability has small impact on polymer retention estimates. Furthermore, the polymer IPV results obtained in the presence and in the absence of oil are very close, ranging from 11.0% to 12.0% of pore volume (PV). This indicates that the presence of oil has insignificant effect on polymer IPV. This study shows that evaluating polymer retention using single phase displacement experiment tends to give an overestimated result, which may lead to a conservative estimate in polymer consumption.
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Best Practices for Pressure Maintenance and Recovery in Reservoirs with Gas Caps
Authors A. AlQasim, M. Alabdullateef, K. Katterbauer and S. KokalSummaryGas cap reservoirs are a special class of hydrocarbon reservoirs that have segregated gas caps and are examples of reservoirs that are at their saturation pressures. The gas and the oil are in equilibrium at reservoir pressure and temperature. Producing a gas-cap reservoir requires special engineering skills. Waterflooding is generally not an option because the gas-cap acts as a pressure buffer (due to gas compressibility) and increasing the pressure by injecting water is difficult. Other production schemes are generally deployed to extract the oil and gas efficiently.
One such method is to produce the oil and reinject the gas back into the gas cap. As reservoir pressure depletes, the gas cap expands, pushing the underlying oil toward the producing oil zone, and wells will begin to produce increasing amounts of gas and ultimately only gas. To maintain the reservoir pressure, gas has to be injected into the gas-cap. The amount of injected gas depends on the size of the gas cap and other reservoir properties.
Some options of injected gases includes the produced gas, lean gas, inert gas or any other gas that may be locally available. Produced or lean gas have been the primary gases for maintaining reservoir pressure in gas cap fields. These gases have no adverse effect on facilities and recovery. Another advantage of this practice is that it relies entirely on gravity drainage, especially in the case of negligible water encroachment.
Other options to consider include CO2 and acid gases. This paper summarizes several methods for pressure maintenance in fields with gas cap. The injectants that were considered include CO2, flue gas, acid gas (H2S and CO2), sour gas (CH4 and H2S). The main motivation is to inject the produced CO2 as a mechanism of mitigating Co2 emissions. This is part of the oil and gas industry’s sustainability options and part of the framework of the circular carbon economy. The advantages and disadvantages of each method on some typical gas-cap reservoirs are investigated. This includes the interplay of recovery, impact on facility and metallurgy, sustainability and economic impact for these options. For CO2 that may be miscible with the oil the option of injecting it into the oil rim is also considered. The long-term contamination of the gas cap is also evaluated.
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Surface Complexation Modeling of SmartWater Synergy with EOR in Carbonates
Authors M. Abu-alsaud, A. Al-Ghamdi, S. Ayirala and A. Al-SofiSummaryInjection water chemistry plays a major role in governing oil recovery from carbonate formations due to its strong effect on wettability. Various studies have shown that surface charge manipulation caused by tailored water chemistry is the main driver behind modifying carbonate reservoir wettability towards a water-wet state. Therefore, understanding the electrokinetics of brine/calcite and brine/crude oil interfaces is important for optimizing injection water compositions for different enhanced oil recovery (EOR) methods in carbonates.
In this work, the physicochemical interactions of various EOR-based water solutions in carbonates are studied using a Surface Complexation Modeling (SCM) approach. First, the brine recipes of NaCl, Na2SO4 SmartWater, and high-salinity water are analyzed as a baseline for zeta-potential comparisons. Different EOR additives, such as surfactants, and dissolved CO2 are added to these brine recipes. The SCM results are compared with experimental zeta-potential measurements for calcite suspensions and crude-oil emulsions in various brine chemistries.
The SCM results for EOR-solutions reasonably capture the experimental zeta-potential trends for both brine/calcite and crude oil/brine interfaces. In surfactant solutions, the anionic surfactants shift the zeta-potential values of brine/calcite and crude oil/brine interfaces toward more negative values for all considered brine recipes with the impact being more pronounced for SmartWater and high-salinity water. For the amphoteric surfactant, which includes both anionic and cationic hydrophilic ends, the surfactant effect is found to be in the opposite direction, where the surface charge has been altered toward a positive direction. For carbonated water, where CO2 is dissolved at high pressure, the magnitude of the zeta-potentials is found to be positive at the two interfaces due to the high activity of H+ surface reactions in both calcite and crude-oil surfaces.
The novelty of this work is that it successfully validates the SCM results with experimental zeta potential data. Such validated models can be used to determine the physicochemical interaction of different EOR-based solutions in carbonates. These modeling results provide new insights on optimal SmartWater compositions that synergize with various EOR methods to yield enhanced wettability alteration and further improvement in oil recovery in carbonate reservoirs.
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Determination of in-Situ Remaining Oil Saturation Before ASP Flooding for Giant Sandstone Reservoir in North Kuwait
Authors B. Baroon, I. Abu Shiekah, C. Chao and M. AL-AjmiSummaryAn Alkaline Surfactant Polymer (ASP) pilot is planned for a giant sandstone reservoir in North Kuwait. The reservoir has good oil recovery, thanks to its favorable geological characteristics, light oil and strong aquifer support. However, the reservoir is exposed to very harsh salinity and temperature conditions that contribute to additional complexity of the envisioned development concept and the costs of the identified and field-tested optimum chemical ASP formulation. Therefore, the determination of remaining and residual oil saturations to water flooding are vital to assess the economic feasibility of ASP field development.
The pilot designed 7 wells have been drilled in mature area of the reservoir and detailed open hole logs surveys were collected in addition to acquiring cores from 3 of the pilot wells in the target zone. Saturation logs show consistently uniform low oil saturation signaling the target zone remaining oil saturation is very close to true residual oil saturation. One of the pilot wells was successfully cored with water based-mud Liquid Trapper technology to reduce the range of uncertainties from quantifying remaining oil saturation.
The Liquid Trapper fluids collected during the coring process were analyzed and only very slight traces of oil were detected. Full diameter cores, horizontal plugs, and vertical plugs in the least invaded parts in the middle of the core covering ∼100 ft interval were cut and prepared for Dean-Stark extraction to estimate oil and water saturation. The results from the analysis confirm low oil saturation range observed from the open hole logs, from a Single Well Chemical Tracer Test (SWCTT) in a nearby well and centrifuge SCAL experiments. However, water saturation estimates from the collected cores were subject to higher uncertainties that are attributed to inevitable artefacts from drilling, coring and core handling operations in addition to new insights on inherited limitations of data analysis from Dean-Stark extraction. The paper will address best practices on integrating data from different sources as well as capturing and highlighting lessons learned.
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FDP Optimization with Techno-Economic Viable Infills and Their Impact in Water/Miscible WAG Injection in Heterogeneous Reservoir
More LessSummaryAn extensive study was conducted to optimize the field development plan (FDP) with infill wells in water and miscible water-alternating-gas (WAG) displacement processes for high and moderately heterogeneous areas of stratified carbonate reservoir. This reservoir is complex heterogeneities with numerous fractures, high perm steaks, multiple sub-layers with variable permeability and intrabed communication with other reservoirs. Within this reservoir, the wells have dual completion through short/ long strings. It is observed that injected water /gas is flowing through high permeability layers and leaving a lot of oil in un-swept area. Therefore, in order to sustain target oil production and improve recovery, this reservoir is currently undergoing re-development with different innovations including maximum reservoir contact (MRC) wells with line drive injection pattern drilled from different artificial islands, gas lift, infill wells, different tubing size strings, different types of well completions (limited entry liner –LEL, pre perforated liner- PPL, inflow control devices- ICD and inflow control valve- ICV) and appropriate EOR technology.
This article presents analytical models and a step by step work flow to optimized FDP for optimum tubing size, well spacing, vertical well placement, well length to reduce the gap between toe to heel of two wells, techno-economic viable number of infill wells and their location (vertical and areal) for maximizing the recovery and maintain the longer plateau at target production rate.
An FDP is formulated with optimum tubing size, well spacing, well length, vertical well location and techno-economic viable infills in water / miscible WAG flooding for a highly heterogeneous complex stratified reservoir.
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One Approach to Waterflood Conformance Control in Carbonate Reservoirs
Authors A. Andrianov, J. Hou, E. Li, E. Liu and L. YangSummaryThe low sweep efficiency of ongoing water flooding in many mature oilfields is attributed to huge permeability contrast or existing high-permeability streaks. Using polymer-based conformance control treatment can be the only viable option to improve oil recovery in many water flooding projects. There are many chemical agents that are developed and used for sandstone formations. However, for the carbonate reservoirs, often characterized by low permeability, fractures, high salinity and temperature, only a limited number of IOR field trials is reported.
The polymeric nanospheres is conformance control agent improving oil recovery through redistribution of water flows deep in a reservoir. The nanospheres are expanding in size after injection into the formation, and swelling period is well controlled. Different classes of nanospheres were developed for various reservoir conditions. Nanospheres are less impacted by geological conditions when compared to other chemical agents and can be used in reservoirs with very high temperatures (upto ∼130°C) and high salinities (upto ∼300,000 mg/l).
There is a long history of application of this agent in sandstone formations that will be briefly reviewed in the paper. Nanospheres have been effective in the reservoirs with permeability as low as 0.1 mD.
Recently, the extensive experimental study was conducted to analyze primarily: a) interaction of carbonate rock and nanospheres (through zeta potential), and b) effect of nanospheres on oil displacement in carbonate cores.
The paper presents evaluation results showing that water quality composition has a great influence on the electrical properties of carbonate rock and nanospheres. In two extreme cases of evaluation (de-ionized water and highest-salinity brine), nanospheres have a uniform charge with rock surface, and there is mutual repulsion that means reduced adsorption on the rock. The positive impact on oil production has been also demonstrated.
Field trial and injectivity tests are essential to de-risk polymer-based IOR technologies.
After the laboratory evaluation the field trial in carbonate reservoir has begun. The nanospheres solution have been injected in two wells. The pilot design included different concentrations and injection rates that were selected after careful review of geological features and ongoing water injection results. The positive impact on watercut and oil rate in producing wells has been reported and confirmed. Furthermore, no loss in injectivity has been observed. This work and field trial can enable the water flooding improvement in carbonate reservoirs through novel IOR method. Besides, nanospheres injection prior to conventional polymer flooding can significantly improve the performance of latter.
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Cold Waterflooding vs. Steam Injection Applicability for Heavy Oil Reservoirs as a Secondary Stage Recovery Method
More LessSummaryPrimary production can be exploited to produce oils with viscosities up to 10,000 cp or even more and usually this stage is followed by water flooding. Since the water temperature is always lower than the temperature of the reservoir, a cooling process starts at this stage and this may continue many years before starting a thermal EOR technique to produce the residual oil which may exceed 50% of OOIP. Injecting a cold fluid may bring many changes into the reservoir, one of which is reservoir temperature change which is the main theme of this paper.
During our simulation of the cooling of the geothermal reservoirs, it has been observed that the natural thermal gradient will not be able to compensate for the decrease in temperature during a long period of injection of cold water. The same behavior has been observed in the case of water injection in oil reservoirs. This phenomenon has been reported since the fifties of the last century in some oilfields in the USA and confirmed by real data measurements at the bottom hole of some wells. This study illustrates numerically how the temperature will drop down on a long time scale. On the other hand, when a steam injection is planned for the next phase of production, a huge amount of energy will be needed to restore the temperature of the reservoir.
To illustrate the above-mentioned theory and observations, a model of a geothermal reservoir is solved to show the cooling process in 3D using a commercial finite element software package. SPE4 Benchmark model is used to compare the ultimate recovery by cold water injection scenario and steam injection counterpart. The temperature change of the reservoir in both cases is shown and compared.
The results show that starting steam injection as a secondary stage in heavy oil reservoirs can save time and gain more profits, especially at the high oil prices phase. Furthermore, the compensation for installing and operating a steam injection facility can pay for itself in a short period of time.
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Novel Approach to Model and Visualize the Transport of Polymer Molecules in Porous Media Using Microfluidics
Authors H. Hoteit, A. Sugar, S. Habuchi, M. Serag, U. Buttner and M. FahsSummaryPolymers have been successfully deployed in the Oil&Gas Industry for various field applications, including waterflood mobility control, flow divergence, and well conformance control. Polymers are among the most widely used chemical EOR methods. Polymer intermolecular interaction and resulting permeability alterations are not fully understood. In this study, we present a novel approach for dynamic visualization of polymer molecular interaction and transport behavior using porous media replication in a microfluidic device, including fluorescent tagging of polymers and single-molecule microscopy. We then use pore-scale simulations to reproduce the experimental observations.
The microfluidic chip, conceptually referred to as “Reservoir-on-a-Chip”, serves as a two-dimensional proxy, which facilitates assessing the flow mechanisms occurring at pore-scale. A microfluidic model was developed to observe polymer flow behavior and transport mechanisms through porous media. The designed microfluidic chip honors the pore-size distribution of oil-bearing conventional reservoir rocks, with pore-throats ranging from 2 to 10 μm. We built the micromodel out of polydimethylsiloxane (PDMS) through soft-lithography.
The traditional use of tracers to track polymers has a limitation because of the tendency of polymer molecules to segregate. Polymer induced pore-clogging, alongside with the reverse mechanism, namely pore-unclogging, have been dynamically captured, for the first time. On the basis of the experimental observation, pore-scale simulations were performed to model the phenomenon. We investigated the flow of the polymer molecules and agglomerates residing in the polymer solution and the clogging-unclogging mechanisms. The simulations emphasize consistent flow conductance increase with time, in the flow channels that underwent unclogging. Both experimental and simulation results bring evidence of polymer retention and attainable flow conductance restoration to the initial pre-polymer flooding values.
We show the first direct dynamic observations of a tagged polymer molecules at dynamic conditions. The conducted single-phase flow experiments enabled direct observation of polymer molecules’ flow behavior within the hosting phase. Additionally, the retention mechanisms manifested during flow and their impact on apparent permeability are analyzed.
The study presents a novel approach for labeling and visualizing polymer molecules and their flow behavior in porous media. We successfully used advanced microscopy techniques, to present dynamic visualization of polymer pore-clogging and unclogging mechanisms, for the first time. Using microfluidic techniques and single-molecule microscopy, we provide new insights at the molecular level, and flow behavior at the pore-scale, which helps to optimize polymer selection for field implementation.
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Carbon footprint forecasting of IOR activities via an intelligent NARX framework for promoting greener reservoir management
Authors K. Katterbauer, A. Marsala, A. Sofi and A. YousifSummaryIntroduction:
Sustainability is increasingly considered a key strategic driver across all industries including oil and gas, and its upstream sector. We continuously thrive to maximize hydrocarbon production while minimizing the associated carbon footprint. In water flooding oilfield operations, the primary driver of carbon emissions is actually water – usage, production, and disposal. The required energy to transport and process the water is considerable, and it is therefore the major carbon emitter. Forecasting carbon emissions from oilfield operations challenges our ability to optimize field development plans in light of carbon footprint besides profit or recovery.
Method:
In this work, we present an innovative approach for forecasting the carbon footprint of a reservoir in terms of the associated development and production activities. We use an advanced nonlinear autoregressive neural network approach integrated with time-lapse electromagnetic data to forecast the carbon emissions from the reservoir in real-time under uncertainty. Within this artificial intelligence (AI) framework, we also incorporate the ability to study the adoption of a circular carbon approach. For this scenario, the AI framework allocate the reinjection of produced greenhouse gases while adjusting water injection levels and forecasts the impact of such circular development plan.
Results:
We tested the framework on a synthetic reservoir encompassing a complex fracture system and well setup. The carbon emissions were forecasted in real-time based on the previous production levels and the defined injection levels. The forecasted carbon emissions were then integrated into an optimization technique in order to adjust injection levels to minimize water cut and overall carbon emissions, while optimizing production levels. Results were promising and highlighted the potential significant reductions in carbon emissions for the studied synthetic reservoir. Moreover, the deployment of deep electromagnetic surveys was found particularly beneficial as a deep formation evaluation method for tracking the injected waterfront inside the reservoir and optimizing the sweep efficiency. Accordingly, such integrated AI approach has a twofold benefit: maximizing the hydrocarbon productivity, while minimizing the water consumption and associated carbon emissions.
Future Outlook:
Such framework represents a paradigm shift in reservoir management and improved oil recovery operations under uncertainty. It proposes an innovative technique to reduce the carbon footprint and attain at real-time an efficient circular injection development plan.
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Smartwater Flooding in Carbonates: The Role of Iodides Ions in Wettability Alteration
Authors A. Gmira, D. Cha, A. Alghiryafi and A. AlyousefSummaryWater injection have been a successful procedure for recovering incremental crude oil from carbonate reservoirs. This recovery method contributes in altering carbonate formations wettability from oil-wet to more water-wet, leading to higher oil mobility and additional hydrocarbon recovery. Recently, the concept of tuning the injected water composition, either by altering the salinity or the ionic composition have gained a significant momentum in the oil industry, encouraged by laboratory and field tests results. Both strategies can make a multiscale adjustment at the fluid-fluid and fluid-rock interfaces, in favor of oil recovery enhancement. However, salinity tuning and ionic composition tailoring have their own challenges and limitations.
In this study, we are investigating the approach of a practical concept in enhanced oil recovery with the addition of Iodide ions in a very small concentration without further treatment. Iodide ions are added to high and low ionic strength brines with different concentrations (500 ppm, 1000 ppm, 2000 ppm and 5000 ppm) to formulate an optimum injected water composition. Contact angle and interfacial tension measurements with selected crude oil are utilized to screen the effect of iodide ions concentration and to study the effect on carbonate rock wettability and crude oil-brine interface. Zeta potential and advanced Sum Frequency Generation (SFG) spectroscopy are utilized to investigate the electric charge variations and to capture the chemical structure changes at the interface.
The initial results show a limited effect of iodide ions on crude oil-brine interfacial values while they alter significantly the rock wettability to stronger water-wet. Zeta potential and SFG measurement brings new insights on understanding the chemical structures at the crude oil-brine interface and how the presence of iodide ions is affecting the interface organization and the structure of organic and inorganic components.
The proposed study is tackling the tailored water injection for EOR purposes from another angle: adding specific ions instead of adjusting the ions levels and ionic strengths. The novelty of this investigation is to bring together routine wettability alteration analysis (contact angle, interfacial tension and zeta potential) and Sum Frequency Generation technique to understand the effect of iodide ions at the fluid-fluid and fluid-rock interface and the potential in-situ changes at low scale. Such understanding is crucial to optimize the injected water chemistry at lower costs.
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Toward Smarter Oilfield Chemicals for EOR/IOR
Authors N. AlJabri, A. Gizzatov and H. ShateebSummaryThe advances in nanotechnology are receiving much attention to transform the oilfield chemicals into smarter, greener and sustainable chemicals. This work describes the synthesis of novel nanofluid via encapsulating superparamagnetic iron oxide nanoparticles (SPIONs) in nanosurfactant (NS), using an inexpensive, scalable, and straightforward method. This nanofluid (NF) is designed to enhance or improve the oil recovery at lower concentrations at reduced cost and, comparing to the conventional chemical flooding. Superparamagnetic iron oxide nanoparticles (SPIONs, 5 and 10 nm in toluene, (5 mg/mL) were obtained from commercial supplier. Different amount of SPIONs was encapsulated into NSs to establish maximum encapsulation concentration. For that, first, 5 and 10 nm SPIONs in toluene were mixed in different ratios with as received Petronate HL/L (61 wt% active) and further formulated into the high-salinity and high-temperature stable NFs. Stability of the formulations in the presence of high salinity was verified through incubation at 100 °C for an extended period. Equilibrated interfacial tension (IFT) measurements were performed using spinning drop tensiometer. The SPIONs encapsulated nanofluid exhibited remarkable colloidal stability at 100 °C and high-salinity of 56,000 ppm of total dissolved solids for over a year. We conducted an equilibrated IFT measurement between different types of crude oil and SPIONs encapsulated nanofluid with corresponding control measurements. Significant reduction in IFT (0.001-0.005 mN/m) was observed for the nanofluid with the encapsulated 5 nm SPIONs when compared to the first generation of NS (0.02 mN/m). The cryo transmission electron microscopy (cryo-TEM) images confirmed the SPIONs encapsulation within the nanosurfactant vesicles. The lower IFT owes to the great synergy between SPIONs and the NS to reduce the IFT by more than two orders of magnitude comparing to NS alone. This work demonstrates the synthesis of economic, efficient and environmentally friendly nanofluid to allow further improve oil mobilization beyond the waterflooding. A novel SPIONs encapsulated nanofluid was synthesized using an inexpensive, scalable, and simple synthesis method. The new nanofluids exhibited colloidal stability under reservoir conditions for a year. The synergy between NS and SPIONs resulted in lower IFT values compared to the use of SPIONs and NS alone. These findings open the horizon to encapsulate a wide range of nanoparticles to generate a library of multifunctional nanofluids to support several upstream applications.
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Low Carbon Foot-Print Reservoir Stimulation Technologies for Improved Oil Recovery
Authors A. Alghamdi, A. Al-Qasim, S. Ayirala and A. YousefSummaryGlobal efforts have been exerted since the 1960s to explore the best technologies for effective enhanced oil recovery (EOR), including thermal, chemical, and gas flooding methods. Yet the adoption and field implementation of these conventional methods is limited. The limitation arises from the fact that those technologies are expensive and mandate substantial modifications in both injection and producing facilities.
In this work, we discuss unconventional improved oil recovery (UIOR) methods that can be implemented in existing waterflooding projects. These technologies include ultrasonic treatment, reservoir electric stimulation, pressure pulse injection, seismic stimulation, and plasma pulse. The main objective is to review the proven best practices and draw examples from ongoing projects. It is also to look at the new horizon for the best feasible solution and provide the most practical option for deploying UIOR technologies in the field.
The ultrasonic treatment targets mainly near-wellbore regions to increase well production rates and decrease water cut. The electric stimulation technology can cover a radius of up to 2–3 km to reduce oil viscosity and remove the clogs in the pore throats to improve oil recovery. The technology is tested in USA and Canada and showed oil recovery enhancements from sandstone reservoirs by applying electric current on pairs of largely spaced wells. The pressure pulse assisted power waves promote greater depth of penetration for the injected fluid to mobilize the stranded oil. The technology has been successfully applied in different patterns of a waterflooding project in eastern Alberta to enhance oil production. The seismic stimulation relies on harnessing low frequency elastic waves either from injection or abandoned wells for increasing oil recovery within a radius of up to 1.4 miles. It has been observed to significantly increase oil production in different formations including carbonates, sandstones, dolomite, and shales. The Plasma Pulse technology uses a high energy plasma source to reduce oil viscosity, and the associated acoustic waves also help in reducing surface tension and increasing oil mobility. This technology is tested widely in Europe and USA to show positive results.
Each of the identified UIOR technologies would result in a lower greenhouse emission and almost no consumption of chemicals. These methods should be selectively screened by taking into consideration the respective technology limitations and uncertainties associated with different reservoir fluids and formation types. The synergy between such technologies could also mitigate some of the individual limitations and enlarge their applicability envelope for eco-friendly and cost-effective improved oil recovery applications.
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Analysis of the Temperature Impact on the Calcite Surface Reactivity in Modified Salinity Water Applications
Authors M. Bonto, A.A. Eftekhari and H. NickSummaryThe success of modified salinity waterflooding (MSW) in carbonate reservoirs is dictated by the interactions between the injected brine and the rock. To describe these interactions, different surface complexation models (SCM) have been proposed. These SCMs usually rely on experimental data at room temperature to obtain the equilibrium constants of the surface reactions. However, these conditions diverge from the actual reservoir temperature, e.g. greater than 70oC in the North Sea. Thus, the existing models cannot describe the surface reactivity at real field conditions unless the temperature dependency of the equilibrium constants is included. The conventional approach to account for the impact of temperature on the surface reactivity is to include an extrapolated temperature effect observed for solution complexation. However, this non-validated assumption may lead to misinterpretation of experimental data.
We address this issue by first identifying methods that give information on the affinity of ions for the calcite surface at different temperatures. We found that calorimetry, streaming potential, and molecular simulations are potential ways that enable capturing the temperature effect on the surface reactivity. Whereas molecular simulations studies provide directly enthalpy data for each defined interaction, calorimetry and streaming potential require geochemical modelling to interpret and break down the observed temperature effect for individual surface reactions. Thus, we perform the modelling of published data from calorimetry and streaming potential experiments by implementing in Phreeqc a Charge Distribution MultiSite Complexation (CD-MUSIC) model, which includes reactions between the calcite and ions relevant for MSW applications; this model is thoroughly validated with experimental data at room temperature. Next, we infer the enthalpy of the reactions by assuming that the equilibrium constants follow a temperature dependence according to van’t Hoff equation. Given the synergy between the interactions, we note that modelling different type of experimental data results in distinct enthalpy values. After a detailed analysis of the experimental methods/simulations, we establish a unique set of enthalpies for the defined reactions. These enthalpies are further verified against flooding experiments in the work of Hosseinzadeh et al. (EAGE IOR 2021) by coupling the reaction module to the single-phase flow equations. The resulting thermodynamic model that accounts for the temperature effect is not only a useful tool for interpreting the laboratory experiments but can also reduce the uncertainty of implementation of MSW projects at the field scale. The study is not only relevant to MSW IOR but also to other non-isothermal reactive transport processes in carbonate formation.
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Integrated Study and Application of Polymer Injection in Arctic Environment
Authors T. Pepe, M. Martin, P. Galeazzi, F. Masserano, M. De Simoni, M. Bartosek, S. Furlani, H. Giraud and V. SalviSummaryThis work presents the interpretation of a polymer injectivity test performed in a heavy-oil field (50–200 cP), located in a challenging arctic environment, during the first half of 2019 to assess the feasibility of the polymer injection process. Following the positive results achieved with the injectivity test, a polymer interwell pilot test started in the last months of 2019, but it was suspended in April 2020 due to Covid restrictions. Thanks to the acquired data during the pilot test, polymer model was tuned into a dedicated sector of the reservoir model, including one injector and two producers.
Using internal company EOR-screening tools, polymer flooding was identified as the most suitable technology for the asset. An integrated study of 3D-modeling and in-house laboratory activities was performed to assess polymer injection potentialities and select the best chemical product for the asset. 3D dynamic analyses confirm the benefits of polymer injection with a significant oil production gain.
Four representative horizontal wells were selected for the injectivity test in order to confirm the injection effectiveness. The selection of injectors was based on an extensive analyses of wells status and performance. The test strategy consisted of 2-weeks polymer injection per well, at constant injection rate and increasing polymer concentration steps. A detailed real-time surveillance plan was realized to monitor injector pressures and polymer solution properties.
The injectivity test was concluded successfully: target viscosity, defined during the laboratory and modeling analyses, was achieved with a limited impact on injectivity. Pressure increase and stabilization during polymer injection confirmed the feasibility of the technique for the reservoir. Well test and temperature profile acquired before and after polymer injection were interpreted.
Once assessed the feasibility of polymer injectivity, a 1-year inter-well pilot started in November 2019. Injection took place up to March 2020 and was suspended due to Covid restrictions. The re-start is planned for mid-2021. During the test several injection and production data were gathered, analyzed and interpreted. In addition to that, starting from the full reservoir model, a detailed sector model was set up in order to match pressures and water cut and forecast the performances of polymer injection.
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Using Surfactant at Ultra-Low Concentration to Unlock Polymer Field Projects
Authors A. Klimenko, V. Molinier, N. Passade-Boupat and M. BourrelSummaryPolymer injection is now a conventional technique for improving mobility control and volumetric sweep efficiency in the field. However, capital and operating expenses are sometimes borderline to ensure profitability, putting the project in jeopardy. An alternative to mitigate this risk would be to significantly improve the oil recovery potential for a low enough marginal cost.
The addition of surfactant is tempting as Surfactant-Polymer injection has proven at the laboratory scale to be very effective to enhance oil recovery, but, with traditional formulation guidelines, the high cost of chemicals and the difficulties in preparing the SP solution are a major obstacle to the project. From this perspective, the objective of this study is to try to adapt the concept of optimal surfactant formulation, without necessarily trying to achieve ultra-low interfacial tensions, to improve the overall efficiency of polymer injection, and thus unlock the potential of polymer projects.
To this end, physicochemical phase behavior of conventional surfactants/crude oil/water systems has been studied to find the optimal formulation conditions at high surfactants concentration. This ultra-low tension formulation was then diluted by more than one order of magnitude compared to “traditional” surfactant designs and was successfully tested in core floods at different injected volumes in order to optimize the design and minimize the cost.
Contrary to expectations, it was found that the optimal formulation used at ultra-low concentrations can sufficiently modify the flow propagation to significantly improve polymer flood. The volume of surfactant injected was optimized to be “good enough” just to upgrade polymer flood without seeking complete desaturation. As so, the limited CAPEX and OPEX that would be required for putting in place this strategy would be game changers on a whole polymer project.
Based on our knowledge, it is the first time that the surfactant formulation of ultra-low concentration shows such promising results. The concentration level is of the same order of magnitude as that of other oil field chemical additives (tens to hundreds ppm), which makes it easy to handle but can considerably extend the application limits of polymer injection.
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Zeta Potential of the Crude Oil-Brine Interface and Implications for Controlled Salinity Waterflooding
Authors H. Collini and M. JacksonSummaryIt is commonly observed that improved oil recovery (IOR) by controlled salinity waterflooding (CSW) coincides with a change to a more water-wet state. An important parameter controlling the wetting state is the zeta potential of the mineral-brine and oil-brine interfaces, which controls the electrostatic forces acting between. Evidence suggests successful CSW is observed when the injection brine composition is modified so as to increase the electrostatic repulsion acting between the interfaces, leading to detachment of oil from the mineral surfaces and IOR on the core- to field-scale.
Measurements of zeta potential at the mineral-brine interface have been reported using the streaming potential method (SPM) at representative reservoir conditions of temperature, salinity and wetting state. It is generally accepted that the mineral-brine zeta potential becomes more negative with a reduction in the injection brine salinity and/or specific ions. However, comparable zeta potential data for the oil-brine interface are scarce. Most report negative values at pH>6, increasing in magnitude with increasing brine dilution, however, these are typically made using commercially available electrophoretic methods which operate far from reservoir conditions, using suspensions of crude-oil droplets in dilute (<0.1M), single-salt species brines and ambient conditions.
Here we report novel and systematic SPM measurements of zeta potential of the oil-brine interface in brines of high ionic strength and containing multivalent ions. A strongly oil-wetting, hydrophobic porous substrate was prepared and coated with the crude-oil of interest. The SPM was used to measure the zeta potential of these substrates when saturated with brines of interest to CSW. We find the zeta potential is negative in simple NaCl brines (up to 2 Mol/L) with the magnitude increasing with decreasing brine salinity, consistent with previous literature. The concentration dependence of a given oil depends on properties such as the acid number and base number. Increasing the concentration of specific ions such as Ca2+ causes the zeta potential to become more positive and for some oils can invert the polarity. The sensitivity of the crude-oil to potential determining ions such as Ca2+ varies significantly dependent on the oil properties.
Integrating these measurements with CSW corefloods, we find diluting the injection brine yields IOR only when the zeta potential of the oil-brine interface is negative. In samples where the oil-brine zeta potential is positive, no IOR was observed, consistent with the hypothesis that IOR is caused by an increase in the repulsive electrostatic force between the mineral-brine and oil-brine interfaces.
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