IOR+ 2025 - 23rd European Symposium on IOR

Polymer flooding is a mature enhanced oil recovery (EOR) technology that has been in use for >60 years. In recent years, the screening criteria has widened to include much heavier oils as the understanding of the mechanisms of polymer flooding has improved. Similarly, advancements in the range of polymer products have resulted in a wider range of applicable reservoir conditions. Specifically, the incorporation of ATBS (2-Acrylamido-tertiary-butyl sulfonic acid) into polyacrylamide-based polymers (HPAM) has significantly increased the polymer’s tolerance to high temperatures and salinities. This inclusion comes at an increased cost per mass of polymer, however without this inclusion the typical HPAM polymers are not sufficiently viscous and quickly degrade at these more extreme conditions.

This work looks to understand if there is value in using polymers with ATBS inclusion in a case taken from the literature with a low temperature of 31 °C and a moderate salinity of 15k TDS. 6 polymer chemistries of equivalent molecular weight are examined: co-polymers of acrylic acid (AA) and acrylamide (AM) - i.e. HPAM; co-polymers of ATBS and AM; and, ter-polymers of AA, ATBS, and AM. The polymers are evaluated in terms of viscosification per mass of polymer and dynamic adsorption via core flooding. The laboratory data is then used as input for simulation of a conceptual field model with an adverse viscosity ratio of-100 and significant water slumping. The numerical model is evaluated in terms of total recovery and net present value (NPV).

The laboratory data shows that the inclusion of ATBS as a ter-polymer results in a significantly higher viscosity yield and lower adsorption than the basic HP AM. When taken into the numerical model, this polymer - despite an increased cost per mass - results in a higher NPV, reduced water production and quicker production of the oil bank. The optimum dosage is found to be ∼20 cP, above this there is little further improvement in recovery or NPV.

This work presents a detailed argument for use of advanced ATBS polymers for lower temperature and salinity reservoirs. These polymers can result in a lower adsorption and higher viscosity yield than the equivalent HPAM. Using a simple economic model, it is shown that these factors give an improved NPV over HPAM in the specific scenario examined, despite the higher polymer cost. In short, these polymers can be advantageous and economic for cases beyond “high temperature / high salinity”.

Polymer injection is now a mature EOR process, and numerous large-scale expansions are currently underway while new projects are being designed all over the world. Curiously, one of the basic design questions still remains highly controversial: what is the optimum viscosity that should be injected? Some practitioners advocate injecting very high viscosities while others advocate just the opposite. The selection of the viscosity to inject has obvious economic implications as it is directly linked to the polymer concentration and thus its cost which can reach tens of dollars for large expansions. This paper will explain why the question still remains without a clear answer using case studies.

The paper reviews the theoretical and practical arguments based on real field experience to help future project designers select the right viscosity for their polymer project. This is a critical issue as this can have an impact on injectivity and economics.

Theoretical methods can be conservative and may lead to over-design. Reservoir simulations have also been used in several cases to justify extremely high polymer viscosities but in some cases field results do not bear out these expectations. The conclusions of this work show that several factors need to be considered when selecting polymer viscosity; beyond injectivity and mobility control which are obvious ones, another important factor is the reservoir layering. Field experience shows that in single layer reservoirs such as those in Canada, lower viscosities can be used but that in cases of heterogeneous, multi-layer reservoirs, higher viscosities are required. Finally, practical concerns for expansions should not be forgotten: practical experience in Daqing for instance shows that injecting at high viscosity can cause severe casing and vibration issues, while theory and practical experience in other fields both confirm that produced polymer concentration could cause severe issues in the surface facilities.

Reservoir and surface aspects need to be considered with the view that even when designing a pilot, large-scale expansion is the ultimate goal that needs to be kept in sight. Expansions require not only successful pilots but also attractive economics and will present challenges beyond those experienced in a pilot such as separation issues in the surface facilities. The paper will provide some guidance for the design of their future projects and provide the context for making such decisions in the framework of large-scale field projects.

Modified injection water, also called Smart Water, has proven to be a successful enhanced oil recovery (EOR) fluid in carbonate rocks. Wettability alteration induced by favourable crude oil-brine-rock interactions taking place by the introduction of an injection water (IW) of different composition than the formation water (FW) leads to accelerated and enhanced oil production. Seawater (SW) injection into the Ekofisk chalk field on the Norwegian Continental Shelf is one such example. The reason for the EOR-effect by SW injection is the favourable composition of SW, containing sulphate, calcium and magnesium ions, which are active in the wettability alteration process.

In areas where SW is not available, the choice of water to be injected in a waterflood would naturally be aquifer brines, the FW, or a source of surface water. According to experimental laboratory research, these latter water compositions are not favourable for wettability alteration in carbonate rocks. Produced water (PW) is initially of a composition similar to that of the FW but will gradually change to a mixture of increasing IW/FW ratio over time.

In the absence of SW, both PW and FW can turn into EOR-fluids if certain ions responsible for wettability alteration are added to those brine compositions. This can be easily done by dissolving a naturally occurring salt, polysulphate (PS) – containing high content of sulphate and calcium ions, into PW or FW.

In this work, outcrop Stevns Klint chalk and Indiana limestone cores restored to mixed-wet conditions using a crude oil with AN 0.6 mgKOH/g were used as the carbonate material. Spontaneous imbibition oil recovery tests were performed, at 110 degC and 10 bar back pressure, to investigate the wettability alteration EOR-potential by the addition of 3 grams of PS salt to 1 litre FW of salinity 63000 ppm. By comparing the oil recovery by PS-spiked FW to that obtained by FW alone, it was clear that the addition of PS turned the FW into an EOR-fluid for both outcrop chalk and limestone at the experimental conditions used. An additional oil recovery of 3–17 %OOIP was obtained in secondary imbibition mode. Thus, in areas where SW is not available or where PW reinjection is preferred, these results indicate that Smart Water can be made by adding PS to PW, aquifer brines, or surface water.

Polymer flooding has been applied in Daqing Oilfield since 1995, and has been successfully used for 30 years, the peak annual oil production has exceeded 10 million tons for 14 years. This paper presents the experiences of applications of polymer flooding, the key reservoir engineering technologies ensuring successful application of polymer flooding, and the challenge to further improve oil recovery after polymer flooding.

Daqing Oilfield has abundant field development data of polymer flooding, including sealed coring well data, well logging data, field production data, and EOR field pilot data. By using these precious first-hand data comprehensively, this paper evaluated the successful experiences, revealed the oil recovery potential, developed a series of key reservoir engineering technologies for polymer flooding, and investigated the challenge and method to further increase oil recovery after polymer flooding.

The analysis of the sealed coring well data and production surveillance data revealed that polymer flooding not only increases swept volume, but also improves oil displacement efficiency. The analysis on field development data suggests that, in order to efficiently develop sandstone reservoirs with multiple pay zones and strong heterogeneity, the polymer solution should enable equilibrium displacement and simultaneous response of all pay zones. Accordingly, a method for matching the polymer molecular weight with reservoir properties is established to ensure polymer solutions are injected into reservoirs with different permeability evenly. Moreover, the key reservoir engineering technologies for field application of polymer flooding are developed, including target reservoir configuration, scenario design, and improving performance method. The research results show that reservoir properties changed greatly after polymer flooding, resulting in that water preferential flow channels formed, its thickness percentage is only 15.9%, but its water injection percentage is high up to 60%, indicating that the biggest challenge to further improve oil recovery after polymer flooding is how to overcome futile cycle of displacing fluid in the water preferential flow channels. A new chemical flooding technology has been successfully developed and applied to the pilot of post-polymer flooding, having ability to increase the oil recovery by 15% after polymer flooding. With the application of the technologies in Daqing Oilfield, the oil recovery of polymer flooding is increased by 14% over water flooding, and the new chemical flooding technology has been successfully developed for field application of post-polymer flooding, showing that these research results have a certain reference value to field application of polymer flooding in the other oil field in the world.

The Voidage Replacement Ratio (VRR) is used to assess the performance of ongoing water floods. Often, it has been experienced that VRR is either used or abused during waterflood management, which leads to inconsistent decisions. Integration of VRR with injection efficiency provides a powerful tool to manage mega-sized water floods in North Kuwait. This article presents various sources of errors in reporting VRRs and suggests a deep-dive approach rather than a simplistic methodology.

The North Kuwait Reservoirs’ portfolio of active water flooding includes componentization, depletion drive mechanisms, weak aquifer support, and injected water recirculating to nearby producers. A comprehensive review integrating all available data was conducted to better understand the subsurface of reservoirs. Once the physics of the flow of injected water were known, the VRRs were computed using data-based artificial intelligence rather than a single value from a simple volume-to-volume ratio for each reservoir. To make quick decisions, smart water flood segment reviews were carried out using diagnostic plots, injection efficiency, and artificial intelligence to scale the VRR for each segment of the reservoir.

Various kinds of VRRs are computed, such as instantaneous VRRs, cumulative VRRs, VRRs for areas below bubble point pressure, VRRs for the active segments or patterns, VRRs in pure depletion mode, VRRs under an aquifer support scenario, and VRRs with quick re-circulation or thief zones. Once all of these values are known, the management of the field, segment, or pattern is done in accordance with the reservoir requirements to scale the allowable and redistribute the injected water for maximum benefit. In addition, the VRRs could address reservoir heterogeneity and connectivity to some extent, which would assist the team in making prudent decisions to plan activities for improving water injection efficiency. Various visualization tools using OFM and Spotfire help in decision-making under the collaborative platform. Using these strategies, the water flood optimization in the Sabiriyah Mauddud (SAMA) reservoir resulted in a 10% reduction in re-circulation water and generated stable water cut performance during the previous years. The possibilities of either an over- or under-injection in any part of the SAMA reservoir are avoided.

A powerful option to incorporate performance-based VRRs and water injection efficiency with a rigorous approach helped the team utilize the water injection resources smartly.

This study assesses seven CO2-type Enhanced Oil Recovery (EOR) methods in a stratified dipping reservoir, including CO2 injection and combinations. It aims to compare their effectiveness in terms of recovery factor, water-cut, and carbon storage capacity using reservoir simulation. The scope encompasses evaluating the efficacy of these techniques for enhancing oil recovery and carbon storage while offering insights into optimal EOR strategies for reservoir management and environmental sustainability.

The study explores the availability of CO2 from natural and industrial sources, including post-consumption flue gas. This study investigates seven CO2-type EOR methods, including CO2 injection, carbonated WAG (CWAG), carbonated water injection (CWI), CO2-WAG, CO2-HC-WAG, Flue gas WAG (FWAG), and CO2 with low salinity water WAG (LSWAG), in a stratified dipping reservoir using a reservoir simulator. These methods are evaluated based on recovery factor, water-cut, and carbon storage capacity.

Results indicate LSWAG, CWAG, and pure CO2 injection as the most effective in enhancing recovery factors (80%, 79%, 78%, respectively), while pure CO2 injection, CWAG, and CO2-WAG demonstrated the lowest water-cuts (64%, 67%, 70%, respectively). CO2-type EOR techniques not only enhance recovery factors but also offer potential for CO2 storage. Particularly, CWI and CO2-LSWAG display significant potential for CO2 storage, with capacities of 80% and 53%, respectively. The findings underline the significance of CO2 injection as a sustainable EOR strategy, particularly in offshore fields where natural CO2 sources are scarce. Industrial CO2 emissions, including those from natural gas processing and fertilizers, and post-consumption flue gas offer viable alternatives for CO2 injection. The study sheds light on the versatility of CO2 sources and underscores their role in sustainable EOR practices. These insights provide valuable guidance for reservoir management, emphasizing the potential of CO2-type EOR methods in enhancing oil recovery and mitigating greenhouse gas emissions, thus contributing to both environmental sustainability and efficient reservoir management.

This study breaks new ground by examining seven CO2-type Enhanced Oil Recovery (EOR) methods in a stratified dipping reservoir. It compares their efficacy in terms of recovery factor, water-cut, and carbon storage capacity using advanced reservoir simulation. Novel combinations like CO2-HC-WAG and FWAG are explored, alongside traditional methods. Results identify LSWAG, CWAG, and pure CO2 injection as top performers in recovery factor, while CWI and CO2-LSWAG show promise for CO2 storage, signaling innovative approaches for sustainable reservoir management.

Extra-heavy oil accumulation in the Lower Burgan reservoir of the Abdali field in Northern Kuwait exhibits a viscosity ranging from 6000 to more than 15000 cP at depths of ∼9000 ft. This paper investigates development solutions including assisted lift natural depletion, polymer injection, and solvent drive for efficient and commercial production of these reserves. The study builds upon the findings presented in two previously published papers by Al-Murayri et al. (2024) , which laid the foundation for this work.

Prior research covered characterizing heavy downhole samples mixed with liquid solvents, creating a comprehensive EOS model for crude oil and solvent mixtures, and conducting polymer coreflood tests. In this study, the EOS model together with the polymer and solvent coreflood results were incorporated for large-scale reservoir simulations. A sector model was highly refined to accurately depict such complex flow displacement. To maximize oil recovery and project NPV, existing wells were reused to design a hybrid EOR method combining depletion, solvent injection, and polymer flooding. Additionally, the feasibility of single-well cyclic solvent injection was assessed.

The best development plan involved three years of natural depletion, followed by three years of liquid solvent injection and continuous polymer drive for as long as the process remains economically viable. Natural depletion was chosen because Abdali’s sand is unconsolidated, making it an attractive option. Depletion initially lowers reservoir pressure, allowing for higher injection rates. Sand production has been, however, flagged as an operational challenge. Simulating polymer injection alone led to significant oil recovery, but its injectivity required verification in a pilot trial due to the absence of observed shear-thinning effects in the laboratory.

Liquid solvent injection was proved to be crucial at various stages. Downhole solvent injection aids in liquid lifting. Near the wellbore, solvent mixed with oil enhances injectivity. Single-well or Inter-well solvent injection creates low-viscosity fluid regions, which can be back-produced or pushed by the polymer. This process can continue as long as solvent loss is minimized.

To the best of our knowledge, the literature on solvent injection has so far focused on vapour solvents. A hybrid liquid solvent and polymer injection for extra-heavy oil recovery has not been studied before. This study proved the feasibility of such a development. When applied at pilot scale, the proposed approach can potentially evolve into a unique opportunity to verify the efficiency and practicality of commercial development. Upon establishing techo-commerical feasbility, this can unlock significant extra-heavy oil reserves.

CO2 EOR is a mature technology which has been applied either as continuous CO2 injection or CO2 WAG since the early 1970s. The number of CO2 EOR projects are increasing with time and a significant increase in the number of carbon capture and storage (CCS) projects has been observed in the last few years. CCS is a key enabler to reduce carbon emissions, recognized to play a key role in the journey to net zero, delivering low carbon energy and featuring prominently in many countries’ climate action plans.

A comprehensive experimental program was designed to investigate parameters that affect gas/CO2 mobility under 2-phase and 3-phase flow conditions. These measurements provide key input parameters for CCS and/or EOR projects. The core flood experiments were performed under reservoir conditions using live crude oil and carbonate core samples of up to 1 ft long and 2 in. diameter. The core wettability was restored by ageing the core in crude oil for several weeks, except for the two-phase gas-water experiments. All gas injection experiments were performed using vertically oriented cores, with gas injection from the top. The experimental results show that: 1- Gas injection conducted under miscible/near miscible conditions in the presence of immobile connate water has the highest mobility and Krg(Sorm)follows a linear curve as expected for miscible floods, 2-During 3-phase flow experiments, the presence of mobile water has significant impact on gas/ CO2 mobility, where CO2 mobility decreases as the mobile water saturation increased at the start of CO2 injection, 3- Mobile water saturation—whether from alternating injection cycles or high initial water saturation in transition zones—has similar effect on gas mobility and hence reduces Krg(Sorm), 4- Gas relative permeability end point Krg(Sorm) showed no cyclic dependent for all gas injection cycles starting at mobile water saturation, 5- The lowest gas mobility is observed in two-phase gas-water displacements, highlighting the critical role of water in blocking gas flow, and 6- The gas/CO2 relative permeability end points are not dependent on their own saturation alone as assumed in three-phase models, significant variation in the relative permeability end points was measured at the same saturation depending on the presence of mobile water.

The results of this study have important implications for the design and performance predictions of CO2/WAG EOR and CCS projects. For example, the presence of mobile water at the beginning of CO2 injection significantly reduces CO2 mobility and hence improving sweep efficiency. However, the reduction of gas mobility in the presence of mobile water reduces gas injectivity.

Carbon capture, storage, and utilization (CCS/CCUS) is a key technology in achieving net-zero emissions. Among various CCUS methods, combining CO2 with injection water increases oil production and reduces overall emissions. However, when CO2 dissolves in injection water, the resulting acidic environment can induce chemical reactions that affect rock integrity, injectivity, and the reservoir’s wettability. This study aims to demonstrate the efficiency of CO2-rich formation water (CFW) for enhanced oil recovery (EOR) compared to conventional formation water (FW) injection. Furthermore, this study assessed the possible geochemical reactions that may occur by injecting CFW into sandstone outcrop and how those reactions might impact the injectivity and wettability of the reservoir rock.

Chemical interactions within the rock-brine-CO2 and rock-brine-oil-CO2 systems in Bentheimer sandstone, consisting mainly of quartz, were assessed. First, the solubility of CO2 in brine and the resulting brine pH were estimated experimentally and through modeling. To evaluate the stability of the rock minerals, ground Bentheimer sandstone samples were exposed to CFW at 80 bar and 60 °C for one month. To detect geochemical interactions, mineral and brine samples were analyzed before and after CFW exposure using scanning electron microscopy (SEM) and ion chromatography (IC). Finally, oil recovery experiments were performed on water-wet Bentheimer cores restored with Swi = 20% and crude oil. The restored cores were initially flooded with FW to establish the baseline recovery. The same cores were cleaned and restored to the initial condition, and this time, CFW was directly injected into the core in secondary mode.

The results confirmed that the solubility of CO2 in brines is limited, <5%, while the brine’s pH was significantly decreased as CO2 dissolved in it. The Bentheimer rock minerals showed minimal reactivity toward CFW in the form of negligible mineral dissolution influencing rock stability. A small difference in oil recovery was observed, in which CFW injection resulted in 2 to 3% OOIP more oil produced compared to pure FW injection. Before conclusions can be drawn about the reason behind the extra oil produced by CFW flooding, further studies are needed as the results demonstrate limited contribution from rock dissolution and oil swelling. The possible contribution from wettability alteration on oil recovery needs to be further investigated in less water-wet sandstone rocks.

The porous plate method is perhaps the best practice method for measuring capillary pressure curves in porous materials including geological reservoir rocks. Such curves are critical for designing secure CO2 storage, estimating hydrocarbon reserves and optimizing hydrocarbon production. However, these tests suffer from prolonged durations of months, which is costly especially when performed at reservoir conditions. During the test, two (generally different) fluid pressures are assigned on each side of the system and fluid production is measured as a response. When the production has stabilized, the system has obtained a saturation corresponding to a capillary pressure equal to the assigned pressure difference. To maximize the test value, many pressure steps are performed within the available time. We propose utilizing Physics-Informed Neural Networks (PINNs) for real-time history-matching, interpretation and decision-making for porous plate experiments. Continuously in time we match the obtained data, accounting for the possible range of solutions, and predict the optimal time at which to change the pressure setting and what the next pressures should be. The approach is compared to a predefined strategy and a rule-of-thumb strategy using first synthetic pressure-production data generated by real CO2-water curves from sandstone and then by direct application to real experimental pressure-production data. The results were compared with those obtained from conventional numerical methods.

The strategy leverages the physics of two-phase flow in porous media and underlying initial and boundary conditions with multi-fidelity observational data. Random Fourier embedding effectively captures non-linearities. Training via random collocation point resampling gave more reliable and efficient computations.

The results demonstrate the effectiveness of the applied strategy in calculation of capillary pressure curve, via real-time history-matching of the experimental data and reporting the uncertainties behind the evaluations. These types of experiments are usually associated with high uncertainty in the relative permeabilities. An advantage of our uncertainty-based approach is the ability to determine saturation intervals where the curves can be determined accurately. The approach also predicts the future states of the system and provides suggestions about the later pressure steps of the experiment. Consequently, both time and financial resources are conserved without compromising quality. In fact, the proposed approach assists deciding the best subsequent experimental setting to further optimize information gained, without significant supervision. Additionally, it empowers scientists to optimize the decisions, automize the calculations, reduce test durations and consequently lower the project expenses.