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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
41 - 60 of 139 results
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The Influence of Crude Oil Flooding and Ageing on Carbonate Core Wettability During Core Restoration
Authors P.A. Hopkins, K. Walrond, I. Omland, S. Strand, T. Puntervold and T. AustadSummaryInjection of a Smart Water, with a modified and optimized ionic composition, is an environmentally friendly and cheap EOR method. To be able to optimize the ionic composition to cause wettability alteration in the reservoir, one must understand the initial wetting of the reservoir. Experimental studies have confirmed that acidic material in the crude oil, especially negatively charged carboxylates, R-COO-, are the most important wetting parameters towards positively charged carbonate surfaces that dictate the rock wettability. The carboxylate molecules bond strongly to the carbonate surface and these crude oil anchor molecules can only be removed from the calcite surface by chemical reactions. Generating representative core wettability during core restoration in the laboratory is important for doing realistic oil recovery studies, capillary pressure and relative permeability measurements.
Very water-wet outcrop chalk cores showing good reproducibility were used to study adsorption of carboxylic material onto chalk. Crude oil with a known acid number (AN) was flooded through water-wet chalk cores with 10 % water saturation. The AN of the eluted oil was measured and the amount of adsorbed acidic organic material was determined. It is a general assumption that aging of a core is a requirement to generate a mixed-wet core. Therefore the wettabilities of aged and non-aged cores were determined and compared by spontaneous imbibition and chromatographic wettability tests. The results of this study first and foremost showed that both the aged and non-aged core behaved mixed-wet, thus aging is not a requirement to generate a mixed-wet core. The two parallel cores adsorbed similar amounts of acidic material, and the chromatographic wettability test results showed similar water-wet surface area in both the aged and non-aged cores. However, since spontaneous imbibition is very sensitive to the location of the oil-wet surface, a difference in capillary forces between the aged and non-aged cores was observed. The non-aged core behaved mixed-wet in a spontaneous imbibition test, while the aged core behaved slightly less water-wet than the non-aged core. It seems that during the aging process the oil components were distributed in such a way to influence the capillary forces to some degree. To conclude, aging is not necessary to change the wettability of an initially water-wet core that has been flooded with crude oil. The acidic polar oil components attach to the carbonate surface immediately upon contact, resulting in a mixed-wet system.
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Interaction of Ionic Species with Calcite and Oil Components in Waterflooding - Theoretical Study
Authors A. O. Alghamdi, M.B. Alotaibi and A.A. YousefSummaryDensity functional theory (DFT) trends in Gibbs free energies and enthalpies were thoroughly studied in calcite. Different coordination was applied for ionic species that exist in seawater and smartwater as well as for carboxylic acids presented in crude oil at distinct two primary hydration sites: >CO3H, >CaOH. The studied hydration sites were proposed based on electro-kinetics besides surface titration experimental studies.17, 18 Interfacial energy runs using the Gaussian 09 suits of program21, with Becke’s three parameter exchange and Lee Yang Parr corrected correlation functional (B3LYP) and 3-21G basis set, based on previous surface sites were performed to account for stability, reactivity and wettability alteration. The calculations predict the most stable complexes for calcite are, CO3H, CaO-, CO3Ca, CO3Mg , CaCO3-, CaHCO , CaH2O+ and CaSO4-. We also demonstrate that free ion species are having a higher free energy in seawater than in case of a complex and thus indicates a more reactivity of complex species to interact with rock sites. Furthermore, corresponding values of free energy and enthalpy change of ions association with calcite surface provided insights about complexes that are most favorable at the surface. This study proposes a mathematical correlation between thermochemistry profiles and wettability alteration, which expresses to us how the surface affinity for a certain organic compound compares with its affinity for water. The calculations agrees with previous experiment findings especially in case of Ca+2, Mg+2, SO4-2,MgOH+1 ,OH-1, and NaCl. Some reversed trend can be explained by the smaller size of the basis set used in the calculations. The results of this insights help in understating the interaction mechanism of this unique systems in order to modify reactivity for enhancing oil recovery (EOR) purposes, and to use the outcomes of this study to pose questions and directions for continuing theoretical efforts destined at linking macroscopic reactivity in case of altering wettability with molecular-level understanding.
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Impact of Anhydrite on the Low Salinity EOR Effect in Sandstone Material with High Clay Content
Authors I. Piñerez Torrijos, M. Risanger, T. Puntervold, S. Strand and T. AustadSummaryAt low oil price, using expensive chemicals in EOR methods is not economically feasible. Injecting water of a tailored composition, i. e. Smart Water, is thus a better option. It has previously been shown that injecting a brine of low salinity (LS), very often results in an increased oil production. In laboratory experiments it has been found that an “in situ” induced pH increase is a key parameter to experiencing a LS EOR effect in sandstones. In a field situation, e.g. Endicott, this pH increase is rarely observed, due to pH buffering by fluids, minerals and sour gases. When a LS injection brine is introduced into a core containing crude oil and high salinity (HS) formation water, desorption of cations from the mineral surface, and a subsequent adsorption of protons, H+, leaves OH−, which increases pH. At high OH− concentrations, the acidic and basic polar organic molecules attached to the mineral surface transform into species of lower affinity to the mineral surface, and are released, leading to increased oil recovery. However, the different minerals present in sandstone can influence the induced pH increase. A pH screening test has been developed to investigate the minerals’ influence on pH. Clays are the main wetting materials in sandstone rocks, and they are also known to be cation exchangers, which can influence pH in the system. Feldspars have also been shown to influence pH in both a positive and a negative way, the latter responsible for the poor LS effect in the Snorre field on the NCS.
A mineral often present in reservoir rock, but usually ignored, is anhydrite, CaSO4. In this paper the LS EOR potential in reservoir sandstone containing anhydrite and significant clay content was tested. Because of the amount of clays, this reservoir should be a good candidate for LS injection. The LS EOR potential was investigated using the pH screening test, oil recovery tests and chemical analyses.
The main results from this study showed that reservoir core material containing anhydrite experienced poor LS EOR effects. When LS brine is injected into a reservoir containing anhydrite, some of the anhydrite dissolves and prevents parts of the cation desorption from the clay surface, thereby lowering the pH increase needed to observe increased oil recovery. Based on this study, other minerals than clays, such as anhydrite, can have a serious influence on the reservoir LS EOR potential, and should not be overlooked.
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Application of Low Salinity Water to Improve Oil Recovery from A Fractured Tight Carbonate Reservoir - A Case Study
Authors A. Emadi, J. Guitián, T. Worku, C. Cornwall, B. Shubber and E. EscobarSummaryCarbonate reservoirs are estimated to contain around half of the total oil and gas reserves in the world. Exploitation of these reservoirs is specifically challenging and their recovery factor is generally lower than clastic reservoirs, due to their structural complexity, local heterogeneities, fracture porosity and the oil-wet-nature of the carbonate rocks.
The principle objective of this study was to investigate through laboratory experimentation, the feasibility of improving oil recovery from a fractured tight carbonate reservoir by spontaneous and forced imbibition of a compatible low salinity water (LSW), with and without a surfactant. To facilitate this objective, core material and reservoir crude oil from an active field were combined with reservoir temperature and wettability restoration, in a series of complementary tests, supported by compelling photographic images. Wettability screening of the restored core samples confirmed an oil-wet system with small tendency for water imbibition, which is typical behavior of such low permeability carbonates. In spontaneous imbibition tests, the samples were exposed to resident formation brine, followed by a LSW (2253ppm), with and without surfactant. The start point for the two-stage imbibition sequence was a residual oil saturation (~ 32%PV), which was representative of the target reservoir, established by centrifuge displacement. Exposure to the formation brine resulted in no additional recovery. In contrast the LSW prompted a reduction in the residual oil saturation of 20.47% (9%OOIP). With the addition of a surfactant to the LSW, there was an apparent improvement in the effectiveness of the displacement process, which lowered the residual oil saturation by 27.02% (13.14%OOIP).
To assess the benefits of forced imbibition of the LSW, a combined “soak-and-drive” sequence was deployed. For a core sample with a restored wettability and an established residual oil saturation of ~ 32% PV, the sequencing almost doubled the additional oil production when compared with spontaneous imbibition tests using the same fluid.
Wettability modification has often been cited as a possible mechanism for the success of LSW, particularly in clastic lithologies. An alternative mechanism for improving oil production has recently been introduced in the technical literature, described as an osmosis like phenomenon. This paper explores the possibility of this type of oil displacement in the context of a carbonate reservoir, with the movement of the LSW from the fracture network into the matrix blocks. The data generated by the experimentation, coupled with the progressive series of photographic images, are presented to give credence to the suggested mechanism.
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Pore-scale Visualization of Oil Recovery by Viscoelastic Flow Instabilities during Polymer EOR
Authors A. Rock, R.E. Hincapie, J. Wegner, H. Födisch and L. GanzerSummaryThis paper provides a new understanding of pore-scale polymer displacement processes, namely an additional oil recovery due to elastic turbulence. Using the potential of state-of-the-art GSG micromodels enables to conduct high-quality streamline visualization which is the key to an improved polymer EOR screening. Thereby enables to understand which properties of viscoelastic solutions contribute to oil mobilization. Moreover, this analysis can be used to optimized subsequently the fluid characteristics in order to achieve a higher recovery.
Single and two-phase polymer EOR experiments were conducted in Glass-Silicon-Glass (GSG) micromodels that resemble porous media. The objective of this work is to investigate the additional oil mobilization associated to viscoelastic flow instabilities encountered during polymer flooding at pore-scale. To set a benchmark for non-viscoelastic flooding processes, polystyrene oxide experiments are presented as well.
Experimental workflow consists of three steps: 1) Saturation of micromodel with a synthetic oil (10% silicon oil / 90% decane) with a viscosity of 25 mPas, 2) Displacement of synthetic oil by an aqueous polystyrene oxide solutions and 3) Displacement of remaining oil by a viscoelastic polymer solutions. All aqueous solutions are dissolved in a 4 g/l TDS brine. Additionally, viscosity of the polymer and polystyrene oxide solution are approximately matched. Furthermore, tracer particles are attached to the aqueous phase to enable high-quality streamline visualization using a high-speed camera mounted on an epi-fluorescence microscope.
Here we show that viscoelastic flow instabilities are highly caused and influenced by fluid properties. It is also shown flow instabilities dependence on pore space geometry and Darcy’s velocity. Streamlines and pressure differential evaluations revealed a dependency of elastic turbulence on solutions’ mechanical degradation/pre-shearing conditions, polymer concentration and solvent salinity. Furthermore, two-phase flood experiments in complex pore-scale geometries have preliminary confirmed that elastic induced flow inconsistency provides a mechanism capable of increasing oil phase recovery by the viscoelastic aqueous phase. Thereby, a polymer flood under elastic turbulence caused 20% additional oil recovery, whereas a polymer flood under laminar flow conditions enhances the recovery by only 5%. Due to high-resolution particle tracing in the micromodels, the main causes of enhanced recovery can be described as: (1) vortices, (2) crossing streamlines, especially near grain surfaces and (3) steadily changing flow directions of streamlines. Thus by adding viscoelastic additives to injection fluids and considering a sufficient shear rate, even a low reynold numbers are able to further enhance the displacement process in porous media by its elastic instabilities.
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Modelling of normal net stress effect on two-phase relative permeability and capillary pressure of rough-walled fracture
Authors A.Y. Rozhko, O.P. Wennberg and S. JonoudSummaryFluid-flow in fractured reservoirs is highly sensitive to the change of effective stress during fluid injection or production. Permeability, capillary pressure and relative permeability of rock fractures to oil and water directly impact the amount of hydrocarbons that can be ultimately recovered; however, these parameters are difficult to measure in the lab as a function of effective stress. This stimulates development of computational algorithms to predict the impact of stress changes on two-phase fluid-flow properties of fractures at depth.
In this work, we developed a numerical approach for determining relationships between normal effective stress, elastic rock properties, fracture aperture distribution, aspect ratio scaling, oil/water interfacial tension, contact angle and two-phase fluid-flow characteristics of rough-walled fractures. We extended a well-established approach developed for modeling of single-phase fluid-flow in rough-walled fractures. According to this approach, the aperture distribution is replaced by a network of elliptical cavities forming connected pathway from the inlet to the outlet. The extension towards two-phase flow is based on our previous analytical model, in which a two-phase fluid-flow is calculated in a deformable elliptical cavity.
The numerical algorithm developed in this work allows quick computation of the impact of the stress-change on two-phase fluid-flow properties of fractured rock. Relative permeabilities of fractures are shown to be non-linear functions of water saturation dependent on the effective normal stress. The capillary pressure-saturation curve for rough-walled fracture is shown to be a function of the effective normal stress. The dependency of fracture permeability, fracture porosity and surface area of open/closed fracture on the effective normal stress is also predicted by the model, which can be used as input parameters for reservoir simulators.
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Associative Polymers as Enhanced Oil Recovery Agents in Oil-wet Formations - A Laboratory Approach
Authors R. Askarinezhad, D.G. Hatzignatiou and A. StavlandSummaryAssociative polymers recently tested for their EOR potential in water-wet systems displayed a good potential for reducing residual oil saturation in polymer-flooded cores. In this work, an oil-wet porous medium was used to investigate these observations. A low molecular weight associative polymer was tested as a displacing agent and its ability to increase oil recovery on chemically treated oil-wet Berea cores was evaluated. Linear coreflood experiments were performed using filtered associative polymer solution as the EOR agent at standard pressure and 60°C temperature.
Results from the polymer floods conducted at an established waterflood residual oil saturation (Sorw) yielded increased oil recoveries, i.e., reduced residual oil saturations, Sor, in the formation. The observed incremental oil production was a function of the injected associative polymer treatment volume; Sor decreased with increased injected associative polymer volume. It should be noted that at laboratory conditions it is often hard to establish and also distinguish a 100% water-cut; in other words, true residual oil saturation, Sorw, is often difficult to be established during water injection.
Oil production profile can be discussed based on fractional flow theory, which defines the true Sorw at 100% water-cut. Whenever the produced water-cut is not precisely 100%, oil saturation in the formation is higher than the true Sorw; polymer injection with an improved mobility ratio compared to the water injection one results in an additional oil production, which could be misinterpreted as a reduction in the residual oil saturation, i.e., enhance oil production. Although this accelerated oil production is an attractive possibility (mobility control), it is not an EOR process. Our results are in agreement with previously reported observations in water-wet media related to the EOR nature of the injected associative polymer as opposed to the traditional mobility control of other, either synthetic or organic, polymers. The same results showed that the polymer mobility reduction is highly affected by the injected polymer velocity at the lower spectrum of velocity values and a correlation for the velocity dependent mobility reduction was developed.
Finally, during the injection of the associative polymer, a column of oil-polymer emulsion was formed gradually in the separator which caused some difficulties and introduced uncertainties in the separator’s fluids level readings, and thus eventually in the fluids saturation evaluation. Resistivity data obtained in real time were used to correct for the overestimated values of oil production during polymer injection attributed to the formation of the oil/water emulsion.
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Investigation of CO2 Application for Enhanced Oil Recovery in a North African Field - A New Approach to EOS Development
Authors R. Khabibullin, A. Emadi, Z. Abu Grin, R. Oskui, H. Alkan, M. Grivet and K. ElgridiSummaryMiscible displacement of oil by CO2 injection is one of the most successful enhanced oil recovery (EOR) processes and has been widely implemented in fields around the world since the early 1980s. The advantage of CO2 compared to the other gases is its high extraction power and dissolution rate. As a result, CO2 can develop the miscibility front in the light and medium gravity crude oils at relatively low pressures.
A comprehensive set of experimental studies were conducted using bottomhole oil samples (BHS) and stock tank oil to investigate the viability of miscible CO2 flood in a North African field. The objectives of the study were:
- To measure physical and thermodynamic properties of the oil and CO2 mixtures
- To investigate minimum miscibility pressure and minimum miscibility concentration.
This paper explains the technical approach that was followed to combine laboratory experiments and simulation studies in order to improve quality of the data and tuning of the equation of state. The study started with standard PVT tests (constant composition expansion, differential vaporization, separator tests and viscosity tests) to measure the physical and thermodynamic properties of the reservoir oil. To characterize CO2/oil interaction the study continued with swelling tests. Miscibility of oil and CO2 at reservoir conditions was investigated by visual techniques and the results were verified by slim-tube analysis.
The data from PVT analysis were used to develop three equations of state (EOS) for the reservoir oil from very early stages of the study. The EOS model was then used to design the CO2/oil interaction experiments and was updated once tests were completed.
Simulation of the slim-tube tests were done in order to: (1) verify that simulated FC and MC MMP lies in the range of measured values in laboratory; (2) select the best EOS for conceptual simulation model; (3) calibrate conceptual model for slim-tube test; and (4) understand combined condensing/vaporizing mechanism for a given oil and estimate thermodynamic residual oil at different pressures. Detailed explanations of vaporizing and condensing drives were given in order to allocate them in combined drive along slim-tube.
For conceptual model preparation special attention was given to establish reference interfacial tension and immiscible base case. Further improvements for experimental set up were suggested based on the simulation.
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Novel Application of Micro-CT and Interpretive Geological Analysis to Assess Asphaltene Deposition by CO2 Injection
Authors A. Emadi, R. Khabibullin, I. Patey, Z. Abu Grin, M. Grivet and K. ElgridiSummaryThe asphaltene related issues are known to cause operational problems during well drilling, completion and production life of oil reservoirs. In many cases, this has a significant impact on the development of marginal fields due to the cost associated with inhibition and/or remediation treatment. Therefore, the understanding of asphaltene properties and deposition potential is an important consideration in the reservoir development and design of the EOR/IOR processes.
This paper introduces a new approach that tries to enhance our understanding of asphaltene deposition by adding petrography analysis and Micro-CT studies to conventional PVT type asphaltene analysis and coreflood tests. The application of this approach for a CO2 injection process is presented as a case study which shows how the addition of interpretive geological analysis can assist our understanding of asphaltene deposition and the mitigation solutions.
The main objective of this study was to investigate asphaltene deposition and permeability impairment during CO2/Hydrocarbon flow in the reservoir rock. Asphaltene onset pressure (AOP) and CO2 titration tests were performed using SDS and filtration techniques to characterize asphaltene phase behaviour. Based on the results of the characterization tests, coreflood tests were designed and carried out using reservoir oil and CO2 with CO2 injection ratios increasing from 0.25 to 1.00. Effective permeability measurements were undertaken before and after test to determine the level of permeability alteration due to asphaltene deposition and fluid rock interactions. Comparison of the permeability data before and after the tests shows average permeability reductions of 31% and 13% for two samples with initial permeability of 23.42 and 251.80 mD, respectively. The inverse relationship between permeability loss and original permeability is believed to be due to the smaller size of pore throats in the low permeability sample which boost effect of damaging mechanisms on the permeability.
The interpretive geological analysis (micro-CT, thin section analysis and dry SEM) showed the permeability loss can be attributed to (1) Fluid-Fluid interactions between CO2 and reservoir oil which results in deposition of asphaltene and, (2) Rock-Fluid interactions between CO2 and reservoir rock which results in clay fines redistribution and removal. The results show that the effect of asphaltene deposition in porosity change is significantly higher than the effect of clay fine redistribution. The micro-CT analysis also show asphaltene deposition takes place soon after mixing between crude oil and CO2.
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What Are the Differences between CO2 Injection Offshore and Onshore?
Authors S. Ghanbari, E.J. Mackay and G.E. PickupSummaryCO2-EOR offshore, has the benefit of CO2 storage in addition to EOR. CO2 flooding in the offshore groups of reservoirs, will be different from the past experience of CO2 flooding onshore. Offshore developments are characterised by fewer wells, larger well spacing and higher rates per well. In this study, different aspects of CO2 flooding in these two groups of reservoirs are identified and compared, and possible opportunities for CO2 flooding offshore are identified.
To evaluate potential differences, CO2 flooding in a geological model was simulated under two different development scenarios (offshore vs onshore). Results show that both models are similarly affected by gravity. Offshore, because of larger inter well spacing, a greater degree of heterogeneity can be identified between well pairs. This makes the flow pattern more stable offshore which means that flow correcting mechanisms will be required to a lesser extent offshore.
The requirement for compression is also greater offshore. There are positive consequences for CO2 flooding offshore. The microscopic sweep efficiency increases due to higher miscibility development; the density difference between CO2 and other reservoir fluids decreases and net CO2 utilisation efficiency will be higher. This makes offshore reservoirs better candidates for coupled EOR and CCS CO2 flooding.
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New Methodology for Numerical Simulation of Water-Alternating-Gas (WAG) Injection
Authors H.A. Alzayer, A. Jahanbakhsh and M. SohrabiSummaryA new methodology is presented to simulate WAG injection scenarios. In addition to properly model three-phase flow, the concept of directional and cyclic hysteresis is modelled to capture the underlying physics. Laboratory measured data is used to validate the proposed methodology.
The approach in this paper is based on updating parameters of WAG hysteresis model during the course of cyclic injection to adequately model the key physical mechanisms in WAG injection tests. For this study, we used ‘Modified Stone 1’ model for calculating three-phase relative permeability (kr) data from measured two-phase kr. We used Land’s parameter (C) and the reduction exponent (alpha) for gas secondary drainage relative permeability as the variable parameters in WAG hysteresis model for matching the coreflood production and pressure data.
Results of this study showed that, by applying the proposed methodology for simulating WAG coreflood experiments at different wettability conditions, better match to the experimental data can be achieved. In this paper, we highlight the shortcomings of the current capability of numerical simulators for simulating WAG injection. Some areas of improvement to the current WAG hysteresis model is introduced and a new methodology is proposed to improve the performance of current simulation procedures for WAG injection scenarios.
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Field Pilot of Gel Barriers Placement for In-depth Fluid Diversion of Horizontal Wells in Jidong Oilfield
More LessSummaryMost of the old oilfields in eastern China have already entered into an ultrahigh water cut period, but their annual oil production and remaining recoverable reserves still occupy a pivotal position. Due to severe edge-bottom water coning, the main horizontal production well G104-5P70 of Gao104–5 block in Jidong oilfield has seen an early water breakthrough while a large amount of remaining oil is still stuck in the high structural region. An innovative in-depth fluid diversion technique, gel barrier placement (GBP), proves to be a promising approach to tap the potential of remaining oil in the period of ultrahigh water cut, which involves injecting gel into the horizontal well at the toe end to form ‘gel barriers’, then the edge-bottom water will bypass these barriers and be diverted into the upper zones where the remaining oil is relatively enriched.
In this present work, sensitivity analysis was carried out to study the influence of plugging location, plugging size and plugging strength on the in-depth fluid diversion effect, and optimization design of the plugging system was then conducted with regard to the agent dosage and slug combination. Simulation results indicate that: (1) the main plugging location should be the upper two layers while the appropriate angle between gel barrier and horizontal wellbore is 45°; (2) an obvious water plugging effect is observed for gel barriers with radial slug length of 80m, horizontal probing thickness of 10m and vertical plugging ratio of 0.6; (3) with the permeability reduction factor around 0.05, gel barrier placement will ensure a comparatively high enhanced oil recovery; (4) three-round injection mode is designed to apply on 1500m3 compound plugging agent for the gel barrier placement. Field application shows that the designed GBP is valid for two years with increased oil amount of 1670t and enhanced oil recovery of 6.4%. Compared with traditional profile control techniques, gel barrier placement has prolonged the water control period, improved the plugging accuracy and reduced the plugging agent dosage. It will provide an effective reference for similar edge-bottom water reservoirs in ultrahigh water cut period to further enhance oil recovery.
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Application of Self-Conforming Well Stimulation Technology in Oil and Gas Fields - Fundamentals and Case Histories
Authors I.J. Lakatos, J. Lakatos-Szabó, G. Szentes, A. Jobbik and Á. VágóSummaryThe primary aim of the research project was to develop an efficient technology to control excessive water production in gas and oil wells. As a novelty, water sensitive petroleum-based solutions were developed, which spontaneously form extremely high viscosity barrier under reservoir conditions when contacting with water. Thus, application of that reservoir conformance control technique in fields becomes independent of placement methods even in case of bullhead treatments. After detailed fundamental and applied studies the technology was deemed matured to test under field conditions. Until now, more than 16 well treatments had been carried out including both oil and gas producers. The project is still running in a gas capped oil reservoirs of the largest stacked hydrocarbon field Algyő, Hungary.
The detrimental (higher than 100 m3/d) water production was the primary factor selecting the target wells to be treated. Evaluating the field results, it was concluded that the treatments prove a multifunctional mechanism. The water production in some wells dropped significantly (from 120 m3/d to less than 30 m3/d); meanwhile the gas production remained unchained. In case of some wells, the water production remained unchained, however, the gas production tripled. Surprisingly, all treated gas producers operating in gas capped oil fields, which never produced liquid hydrocarbons started to produce substantial amount of oil (between 10% and 75% oil in net fluid rate). These positive results can be attributed to three different reasons: effective barrier formation against water influx, reducing skin factor caused by formation damage, and opening new flow paths from entrapped oil bodies existing below the gas cap. Thus, the treatment technology was qualified as a “multifunctional well stimulation” contrast to the original term of “water shutoff” method. Based on the encouraging field results the technology became one of the strategic projects of the company in the coming years until 2020.
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Silicate Gel for In-depth Placement - Gelation Kinetics and Pre-flush Design
Authors A. Omekeh, A. Hiorth, A. Stavland and A. LohneSummarySodium silicate gel has historically been used in the oil industry for near wellbore water shut-off. Relatively recent application of Sodium silicate gel for in-depth water diversion have generated some interest. Its main advantage is that its mobility is water-like before it gels. For in-depth diversion purposes, the gelation kinetics need to be appropriately modeled for better prediction of gel placement. This paper makes a review of different gel kinetics models found in the literature. To our knowledge, the models presented in the literature are fit-for-purpose, i.e. they are based on correlations that are fitted to the lab data. Although they describe the lab data well, it is challenging to use them to predict field scale operations, where there are significant temperature, pH, and salinity gradients throughout the reservoir. In this paper, we present an improved silicate gel model. Our model takes into account two important rate step in the formation of silica gel from a sodium silicate solution: the nucleation rate of monosilisic acid to form critical nucleus of nanosized colloids and an aggregation rate of the nano-colloids to form a pore blocking gel. It is important to allow for nano sized colloids as these are small enough to be transported a significant distance from the well before they aggregate into larger clusters that can block the pores. The model explains well the experimental observations where the gelation time is sensitive to pH, temperature, silicate concentration and brine composition. We also investigate the preflush volume and concentration that is needed to minimize the indirect rock-brine interaction that can alter the designed gelation time. Results from this simulation shows that the Cation Exchange Capacity (CEC), Mineral distribution and Temperature profile are critical design criteria for the preflush volume and concentration.
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Simulation of Sodium Silicate Water Diversion Using lORSim
More LessSummaryWe demonstrate that it is possible to predict the impact of a sodium silicate injection on oil recovery by using a coupled approach where an industry standard reservoir model, Eclipse, interacts with a simulator for species transport and reaction, IORSim, using file based communication. The main motivation for our approach is that it makes it possible to take advantage of history matched industry standard reservoir models and use these models together with new models for ion transport and geochemical reactions.
In IORSim a block sorting technique is used to speed up the computation of species transport and chemical interactions. IORSim also has a thermal model which can be used if the temperature option is not used in the reservoir simulator.
The validity of our approach has been checked by comparing with analytical solution and by comparing with an in-house reservoir simulator. Our in-house version solves the multiphase sodium silicate system implicitly. We demonstrate that it is possible to get the very similar results with the sequential IORSim-ECLIPSE coupling and our in-house reservoir simulator by choosing reasonable reporting steps in ECLIPSE. The numerical scheme is improved by using an adaptive implicit numerical scheme and a Cranc-Nicolson method for solving the geochemical reactions.
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Snorre In-depth Water Diversion Using Sodium Silicate - Evaluation of Interwell Field Pilot
Authors V.R. Stenerud, K. Håland, K. Skrettingland, Ø. Fevang and D.C. StandnesSummaryDeclining oil production and increasing water cut in mature fields indicate the need for improved conformance control. In this paper we report on the numerical modeling performed to evaluate the in-depth water diversion pilot performed for the Snorre field, offshore Norway. For this pilot 240 000 m3 of a sodium silicate solution was injected in the period July to October 2013. The goal of the pilot was to form an in-depth flow restriction for improving the sweep. The setup, execution and measured data from response monitoring for the pilot have been presented in previous papers. As discussed therein, the operation clearly resulted in a strong in-depth flow restriction resulting in delayed tracer responses and decrease in the water cut. However, the monitoring was only limited to well observations, so to understand the spatial and temporal forming of the flow restrictions we had to rely on numerical simulation and modeling. In short, we calibrated simulation models to the observed well responses by introducing flow restrictions; i.e. using history matching techniques.
Through the reservoir modeling work we reproduce the pilot response well by introducing sound flow restrictions. This gives us clear indications on the location, timing, strength and corresponding uncertainties of the introduced flow restriction. Moreover, the modeling work supports interpretations from the response monitoring program. Finally, in addition to help evaluating the performed pilot, the learnings from the modeling work will hopefully give more accurate evaluation of potential future water diversion candidates.
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Temperature-switchable Polymer for Enhanced Oil Recovery
Authors R. Reichenbach-Klinke, A. Stavland, T. Zimmermann, D. Strand, H. Berland and C. BittnerSummaryA new copolymer based on hydrophobically modified Polyacrylamide was characterized by its rheological behavior. Viscosities were measured at various temperatures and salinities in comparison to a regular acrylamide/sodium acrylate copolymer (HPAM). It is proven that the viscosity of this new associative polymers increases with temperature, while the viscosity of HPAM is decreasing.
This effect was further explored in porous media studies. Polymer solution was injected into a Bentheimer sandstone with a permeability of around 2 Darcy at 20°C and the pressure drop was measured along the core. From the pressure drop the resistance factor, RF, was derived, which is a measure of the in-situ viscosity in the porous medium.
Next, the temperature was increased to 45°C. This resulted in an increase of the RF from 15 to 94. At 60°C a RF of even 152 was observed. By reducing the flow rate from 0.5 ml/min to 0.1 ml/min the RF could be further increased to 562. Finally the flow rate and the temperature were set to the initial values and a RF of 21 was measured, which shows that the thermothickening behavior of the novel polymer is reversible. Monitoring the effluent viscosity indicated that the increase of the RF / in-situ viscosity is due to polymer being retained in the porous media. This retained polymer lowers the permeability of the rock pores and thereby increases RF. By lowering the temperature the properties are switched back to the original state and the polymer is released from the rock matrix.
The thermothickening behavior of the discussed copolymer can be quite beneficial for polymer flooding applications. During injection at surface temperature the viscosity of the fluid is low and therefore it can be injected at high rates. Once the polymer solution migrates deeper into the reservoir formation, the temperature of the fluid will rise gradually; in-situ viscosity will increase and simultaneously the flow rate will decrease. Both effects will help to improve sweep efficiency.
In general, the magnitude of the RF can be adjusted by modifying the polymer structure and hence the copolymer can be optimized for specific field conditions.
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Design, Characterization and Implementation of Emulsion-based Polyacrylamides for Chemical Enhanced Oil Recovery
Authors A. Thomas, O. Braun, J. Dutilleul, F. Gathier, N. Gaillard, T. Leblanc and C. FavéroSummaryPolymer flooding is a widely used chemical technique used to enhance or speed up oil recovery from brown or green fields. Polyacrylamides used in chemical enhanced oil recovery processes can be supplied either in powder or inverse emulsion forms. The latter has several benefits for offshore deployment including smaller equipment footprint for dissolution and easier transportation to the site compared to the products in solid form. However, the emulsion is a multi-component system that requires much more attention during the formulation and the implementation than the polymer in powder form; the surfactant package must be adapted to the brine used for inversion (temperature and salinity) in order to allow a perfect release of the macromolecules and a good dispersion of the oil droplets to avoid injectivity issues. Moreover, depending on the field conditions and the dosages that are used, the interactions between the components of the emulsion and the crude has to be studied. This paper reviews the basics of emulsion formulation and design along with the best practices for evaluation in the laboratory. Basic inversion procedures for rheological evaluations, filtration tests and oil droplet size analysis are described. An attempt is made to list relevant tests that can quickly allow to discard bad formulations. A quick review is presented on the propagation of emulsions in porous media along with the possible interactions between the components of the emulsion and the reservoir. This is illustrated with several core floods performed using Bentheimer cores where pressure profiles, resistance factors and residual resistance factors as well as mitigation techniques are carefully studied in various injection conditions (low and high temperature, with or without crude oil) and compiled with other laboratory tests such as droplet size measurement to isolate the contribution of each component. The discussion is concluded with engineering and logistic aspects to discuss the proper implementation of such product in the field.
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Enhanced Polymer Flooding - Reservoir Triggering Improves Injectivity and Eliminates Shear Degradation
Authors W.J. Andrews, S.E. Bradley, P. Reed, M. Salehi and D. ChappellSummaryThis paper describes a successful program of lab and pilot-scale studies qualifying a new shear-resistant, high-injectivity, reservoir-triggered polymer (Polymer) for field trial. The Polymer mitigates two of the major operational and economic challenges facing polymer flooding applications for mobility control, namely, shear degradation during injection and reduced fluid injectivity.
Shear degradation of conventional HPAM polymers through injection facilities can result in dramatic losses of up to 70% of viscosity yield. However, this can be eliminated using the new Polymer. This is particularly important in an offshore environment where highly-shearing subsea chokes are required for flow distribution control.
The Polymer formulation uses a novel yet inexpensive chemical approach enabling it to inject with near-water viscosity in a shear-resistant form. The Polymer has been engineered such that it does not viscosify the injection fluid until it is triggered in the reservoir away from the near wellbore region. Higher injection rates and viscosities can therefore be attained than would otherwise be possible with a conventional polymer flood.
Methods:
The Polymer’s triggering performance in porous media under both static and dynamic conditions has been demonstrated. The un-triggered Polymer has been subjected to extremes of shear at both lab and pilot-scale to test shear resistance. Injectivity of the Polymer has been assessed through an extensive suite of sand pack and coreflood experiments. Tests have also been conducted to verify the Polymer’s suitability for field deployment including surface storage, inversion, and long-term reservoir stability.
Results:
The Polymer is completely shear-resistant during injection, demonstrated by flowing through a scaled choke with pressure drops exceeding those expected during deployment. The viscosity of the un-triggered Polymer solution has been shown to be almost independent of the Polymer concentration, injecting with a viscosity close to that of sea water and giving excellent injectivity into sand packs and cores. In addition, the Polymer has been demonstrated to inject, propagate and trigger to deliver a pre-determined viscosity in a temperature-controlled 40ft sand pack experiment. The Polymer solution is easily and reliably prepared, out-performing a conventional HPAM in a pilot-scale inversion study, and demonstrates storage characteristics above the industry standard. A 15 month-long stability test performed at reservoir temperature with reservoir fluids showed minimal loss of viscosity.
Testing will now proceed to field trial. If successful, this new technology offers a route to overcoming some of the key obstacles to large scale polymer EOR deployment, particularly in the offshore environment.
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Qualifying an “Emulsion” Polymer for Field Use - Lab-scale Assessments on Adsorption and Injectivity
Authors K. Sandengen, M.T. Tweheyo, C.M. Crescente, A. Mouret, I. Henaut and D. RousseauSummaryPolymers prepared as concentrated inverse emulsions (“emulsion” polymers) appear valuable for offshore EOR as they involve simple dilution procedures. However, recent studies have shown that these polymers could entail permeability reduction effects which question their injectivity.
Initial screening tests, for a specific high temperature and high salinity field case, showed no sign of plugging. Adsorption was, however, reported to be extremely high and a more elaborate work package was therefore initiated.
An “emulsion” polymer and its “dry” equivalent (from which oil and most surfactant were removed) were put through coreflood tests focused on injectivity (including plugs with intermediate pressure taps) and adsorption (evaluated from measurements of the irreversible retention). Injection in porous media, at reservoir type rates, revealed increases of the resistance factors, RF, in two successive fronts: a “quick” front with RF values consistent with the polymer viscosity and a “slow” front with much higher RF. The quick front corresponds to the propagation of the viscous polymer, as is it associated to the polymer breakthrough. The slow front is attributed to the deposition of oil droplets coming from the synthesis process of the polymer. Similar behavior has been observed from tests carried out in monophasic conditions, in presence of residual oil and at different injection velocities, but not with solutions of the “dry” polymer sample. As oil droplets impact the polymer inaccessible pore volume and hence the volumes at breakthrough, a specific procedure had to be developed to determine polymer adsorption. With this procedure the “emulsion” and the “dry” polymer samples yielded comparable results. Following this work package adsorption was consequently no longer a concern, while injectivity again proved questionable. Finally a new version of the “emulsion” polymer, with an improved surfactant formulation package, was injected through porous media with no sign of plugging/pressure build-up.
In conclusion we do not foresee problems associated with the chosen “emulsion” product. In the laboratory we have, however, not mapped all rate regimes nor with actual mineralogy. Hence sufficient emulsion propagation cannot be guaranteed (in particular as the permeability damage could propagate in-depth). Injectivity therefore still remains as one major factor to be investigated in the coming field trial.
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