Rognmo, Arthur U. (University of Bergen) | Al-Khayyat, Noor (University of Bergen) | Heldal, Sandra (University of Bergen) | Vikingstad, Ida (University of Bergen) | Eide, Øyvind (University of Bergen) | Fredriksen, Sunniva B. (University of Bergen) | Alcorn, Zachary P. (University of Bergen) | Graue, Arne (University of Bergen) | Bryant, Steven L. (University of Calgary) | Kovscek, Anthony R. (Stanford University) | Fernø, Martin A. (University of Bergen)
The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.
We present a CT coreflood study of foam flow with two representative oils: hexadecane C16 (benign to foam) and a mixture of 80 wt% C16 and 20 wt% oleic acid (OA) (very harmful to foam). The purpose is to understand the transient dynamics of foam, both generated in-situ and pre-generated, as a function of oil saturation and type. Foam dynamics with oil (generation and propagation) are quantified through sectional pressure-drop measurements. Dual-energy CT imaging monitors phase saturation distributions during the corefloods. With C16, injection with and without pre-generation of foam exhibits similar transient behavior: strong foam moves quickly from upstream to downstream and creates an oil bank. In contrast, with 20 wt% OA, pre-generation of foam gives very different results from co-injection, suggesting that harmful oils affect foam generation and propagation differently. Without pre-generation, initial strong-foam generation is very difficult even at residual oil saturation about 0.1; the generation finally starts from the outlet (a likely result of the capillary-end effect). This strong-foam state propagates backwards against flow and very slowly. The cause of backward propagation is unclear yet. However, pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. Implicit-texture foam models for enhanced oil recovery cannot distinguish the different results between the two types of foam injection with very harmful oils. This is because these models do not distinguish between pre-generation and co-injection of gas and surfactant solution.
Nguyen, Nhat (The University of Texas at Austin) | Ren, Guangwei (TOTAL E&P R&T, USA) | Mateen, Khalid (TOTAL E&P R&T, USA) | Ma, Kun (TOTAL E&P R&T, USA) | Luo, Haishan (TOTAL E&P R&T, USA) | Neillo, Valerie (TOTAL SA) | Nguyen, Quoc (The University of Texas at Austin)
Low-Tension Gas (LTG) has emerged as a novel enhanced oil recovery injection strategy, employing foam in place of polymer to displace the oil bank created with the help of ultra-low-IFT (ULIFT). In our prior work, the process was successfully employed, both in sandstones and carbonates, to achieve attractive oil recoveries with relatively low surfactant retention. However, earlier experiments were carried out at high flow rates in relatively high permeability cores. To improve the robustness of this novel injection scheme, it is necessary to examine it under wider practical environments. Therefore, in this work, experiments are conducted in carbonate and sandstone cores, at lower injection rates and rock permeabilities, to determine whether the foam could provide the necessary mobility control with this novel EOR technique. Initially, a lower flow rate (1 ft/D) experiment is conducted in relatively high permeability (388 md) sandstone core to compare it with the earlier results under a higher injection rate (4 ft/D). Subsequently, even further reduced injection rate (0.5 ft/D) is employed in a sandstone core with one order of magnitude lower permeability (36 md). Two other corefloods with Estaillades limestone (166 md) and Richmont (7 md) are carried out to extend the comparison to carbonate rocks. Surfactant retentions are determined. It is found that four-times-lower injection rate (1ft/D) just slightly delayed oil production, and achieved comparably high oil recovery (87%), indicating a good mobility control. Proportionally reduced pressure drop during slug injection implies similar total fluid mobility. Accordingly, salinity propagation examined from effluents shows slight delays. Even with ten-times-lower permeability sandstone (36 md) at a lower total injection rate (0.5 ft/D), comparable oil recovery (84%) and salinity propagation are found, despite of much lower foam strength. With an intermediate-permeability Estaillades limestone (166 md), compared to high permeability sandstone, oil production is delayed, but comparable eventual oil recovery (88%) is obtained. The delay could be due to higher surfactant retention (0.301 mg/g). The delayed effluent salinity propagation is noticeable, which may be caused by increased total fluid mobility. Finally, extremely low permeability Richmont (7 md) indeed adversely impacts the oil recovery (~58%) and the salinity propagation. This could be attributed to higher surfactant retention and/or decreased foam stability due to oil-wet rock surface. The works here test the robustness of the LTG process in more practical reservoir conditions and have widened its applicability. Demonstration of its feasibility in low-permeability reservoirs, where use of polymer is not currently feasible, will greatly promote the testing and deployment of this technology in the future.
This review is based on latest application of nanoparticles in hydraulic fracturing, and their feasibility as compared to other conventional methods. Focusing on technical, economic, mechanisms and direction of future research. Current status and advancement give a promising future application by using unique properties of nanomaterials such as small sizes, stability, magnetic properties and surface area which are yet to be exploited to full potential. Nano materials can be inculcated in drilling in all forms. From acting as additives in drilling mud there by enhancing density, gel breaking strength, viscosity, acting as a proppant, cross linking agent etc.
There are certain problems which are difficult to overcome using macro and micro type additives due to limitations in physical, chemical and environmental characteristics. Hence, the scientists are looking for such smart fluids which can overcome these limitations. Compared to their parent materials, nanoparticles can be modified physically, chemically, electrically, thermally, thermodynamic properties and interaction potential of nanomaterial. However more investment, work and pilot projects are required to understand properties of nanomaterials at reservoir temperature and pressure.
Nanomaterials such as aluminium oxide, zinc oxide, copper oxide, silicon dioxide, low cost carbon nanotubes, fly ash nanoparticles in unconventional reservoirs need to be further researched. Moreover, focus should be put on economic analysis, performance at reservoir conditions, cross linking and agglomeration properties, wettability alterations, interfacial tensions properties. The enhanced hydrocarbon recovery from unconventional reservoirs through wettability alterations and interfacial tension decrement by nanomaterials and combined use of fracturing fluid system comprising of VES, foams, proppants gives a promising future application.
Enhanced-Oil-Recovery processes for Naturally-Fractured Reservoirs usually require fluids mobility control in the fractures, which can be ensured by foam-based processes. The latters have to demonstrate stability over very long distance as their efficiency rely on the pressure increase in the fractures network. Despite their potential, the ability of foams to propagate and regenerate in fractures, but also the most adapted design of foaming-surfactant formulations, are poorly documented. These issues are addressed in this experimental paper.
The propagation of foams over long-distance fractures (from 100 to 1000 meters) is modelled at the lab-scale by a flow of pre-formed foams in long vertical and horizontal tubings (from 0.01m to 10 meters). The visualization of the flowing foam and the measurement of pressure allow identifying the physical phenomena which account for foam evolution in horizontal and vertical configurations. Comparison of performances is also conducted for several formulations differing by their foam performances in sandpack and by their wettability alteration properties.
A preliminary test shows that co-injection of gas and liquid in a representative oil-wet fracture generates very poor foams, unlike classical porous media (sandpacks, rock core samples). This poor rejuvenation of foam evidences that foam flow in fracture strongly differs from observations in porous matrix and highlights the need for long-term foam stability. In long tubings, characterization of different formulations first shows that the most efficient foams do not correspond to the best formulations identified for porous media. Criteria to optimize a foam formulation for fracture network seem specific. Second, the evolution of flowing foams highly differs from static foams and highlights the difference of performances brought by the flow. The local foam flow structure is different from one formulation to another. These results suggest that the ability to create a high pressure gradient depends on wettability properties of formulation, due the strong interaction of foam lamellae with walls along the flow.
To ensure an efficient foam-based process in a fractured reservoir, long-term stability is crucial yet not predicted by classical criteria based on porous media experiments. Besides, the best foaming-surfactant formulation for fractured systems corresponds to new criteria, likely related to wettability instead of apparent viscosity. This work has important implications on the design of foam injections in naturally fractured reservoirs regarding the calculation of liquid volumes, injection strategy to ensure foam propagation over long-distance.
Luo, Haishan (TOTAL E&P R&T, USA) | Mateen, Khalid (TOTAL E&P R&T, USA) | Ma, Kun (TOTAL E&P R&T, USA) | Ren, Guangwei (TOTAL E&P R&T, USA) | Neillo, Valerie (TOTAL SA) | Blondeau, Christophe (TOTAL SA) | Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Biswal, Sibani (Rice University) | Hirasaki, George (Rice University)
Recovering oil from oil-wet matrix in fractured carbonate rocks is highly challenging. Recent experiments have indicated that ultra-low-interfacial-tension (ULIFT) foam flood could significantly boost the oil recovery from such rocks. However, there is limited information available about the foam and the microemulsion transport in the fractured system to extract the oil from low permeability matrix. Adaptation of this technology in the field would not be possible without a good understanding of the process.
The aim of this work is to model and history match the ULIFT foam flood in fractured carbonate cores for further gaining insight into the complex four-phase flow. The model was set up based on a group of experiments using cores split lengthwise to simulate axially confined fractures. Pre-generated foam was tested in this system due to the lack of in-situ generation of foam in the straight fracture at the core scale. Various foam coalescence mechanisms, with/without oil, were modeled, and a dynamic-texture population-balance foam model was developed for this purpose.
Our model incorporates the effects of oil and permeability as well as the coexistence of foam and microemulsion on the foam apparent viscosity. The model is able to reasonably well history match both the oil recoveries and the total pressure drops of the ULIFT foam floods in fractured carbonate cores. More impressively, the modeling results agree very well with the pressure gradient of each section of the core, indicating that the spatial variation and distribution of the foam texture are largely captured. The simulation results also show that the pre-generated foam greatly resists the fluid flow in the fracture close to the injector side and enhances the diversion of injected fluids into the matrix layers, leading to improved oil displacement. The resulting oil crossflow from the matrix to the fracture destabilizes the foam at the foam front thereby slowing the transportation of foam in the fracture. Additional case studies suggest that significantly more oil can be recovered if the foam destabilization by oil could be reduced/mitigated.
Test results disclosed in this paper demonstrate for the first time the successful modeling and history-match of ULIFT foam floods in fractured rocks. Valuable insight into this complex process has been gained through this innovative research. This is of great value with respect to the further optimization of the corefloods, the design of the surfactant formulation, and the feasibility of applying this new technology to the field scale.
Soulat, A. (IFP Energies nouvelles, Geosciences Division) | Douarche, F. (IFP Energies nouvelles, Geosciences Division) | Flauraud, E. (IFP Energies nouvelles, Applied Mathematics Division, Rueil-Malmaison Cedex - France)
An accurate evaluation of injectivity is essential to the economics of any chemical EOR process. Most commercial simulators enable non-Newtonian behaviour modelling but it is often overlooked due to inadequate grid resolution. Indeed, in cases where shearthinning fluids are injected in a reservoir, shear rates and viscosities in the vicinity of the wellbore can be poorly estimated if the spatial resolution of the well grid-blocks is too coarse. This results in biases in injectivity and economics which we discuss here in the context of foam-based displacements.
We consider continuous foam injection in models of different spatial resolutions ranging from 1 to 100 m gridblock sizes and study the behaviour of injection wells obtained on the coarser grids compared with the results from a high resolution grid. This reference grid is sufficiently refined to account for near-wellbore large velocity gradients and render injectivity accurately. In this work we propose new formulations of the well index that capture shear-thinning behaviour that the conventional Peaceman calculation fails to address.
We first demonstrate that a poor evaluation of near-wellbore velocity leads to erroneously degraded injectivity on the coarser grids when compared to the reference grid. In order to correct these errors our modified well index is applied and validated in various scenarios of foam displacement simulation with radial grids. It captures a more accurate injectivity than the conventional Peaceman calculation once steady-state regime is reached. The modified well index we propose, used under a simplified form as direct input in reservoir simulation, significantly enhances injectivity estimates without resorting to grid refinements or modifying the shear-thinning model of the injected foam. In most cases it yields results that are closer to those obtained using grid refinements than the Peaceman formula at a much more attractive computational cost. Additional work remains to complete our understanding of injectivity in more complex settings, especially in the context of foam injection when effects such as foam dry-out and destruction in the presence of oil are as important on sweep efficiency as its shear-thinning behaviour.
Our workflow successfully corrects biases in the estimation of injectivity and yields more accurate results and avoids resorting to time-consuming methods such as grid refinements and physical input data alteration. Moreover it is simple to implement in most commercial simulators and does not require using empirical criteria. However, it bears some limitations which we also discuss.
Abdul Ghani, Mohamad (IFP Energies nouvelles) | Ayache, Simon Victor (IFP Energies nouvelles) | Batôt, Guillaume (IFP Energies nouvelles) | Gasser-Dorado, Julien (IFP Energies nouvelles) | Delamaide, Eric (IFP Technologies Canada Inc)
Although SAGD is a very popular in-situ extraction method in Canada, this thermal process relies on huge energy and water consumption to generate the steam. Irregular growth of the steam-chamber due to heterogeneities further degrades its yield. Contact between the steam chamber and the overburden also leads to heat losses. The objective of this paper is to investigate how Foam Assisted-SAGD could mitigate these technical issues and improve the efficiency of the SAGD process. Compositional thermal reservoir simulations are used to simulate and analyze a Foam Assisted-SAGD pilot. The shear-thinning effect close to the wells is also accounted for. The simulations are run on a homogeneous model mimicking the Foster Creek project in Alberta, Canada. Several type of injection sequences have been analyzed in terms of foam formation, back-produced surfactants and cumulative Steam-Oil-Ratio. Results are compared with the original SAGD performance. In order to propagate the foaming surfactants throughout the steam chamber the injection sequence needs to be properly determined. A simple continuous Foam Assisted-SAGD injection would lead to an accumulation of surfactant between the wells due to gravity segregation, preventing the foam from acting on the upper part of the steam chamber. Furthermore surfactant production occurs after a few weeks due to the proximity of the producer and the injector. A proper injection strategy of the type SAGD/slug/SAGD/slug is found to delay the chemical breakthrough and increase the amount of surfactant retained in the reservoir while allowing the surfactant propagation throughout the steam chamber. After optimization the Foam Assisted-SAGD process appears to be technically promising.
This paper presents an analysis of a CO2-foam-injection pilot in the Salt Creek Field, Natrona County, Wyoming. A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Aqueous foam has been demonstrated to have promise in conformance-control applications. This paper explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant.
Pipeline pigs are devices that are placed inside the pipe and traverse the pipeline. Pigs may be used in hydrostatic testing and pipeline drying, internal cleaning, internal coating, liquid management, batching, and inspection. Figure 1 shows several types of pipeline pigs. The pig is inserted ahead of the fill point, and water is pumped behind the pig to keep the pipe full of water and force air out ahead of the pig. Pigs are then used to remove the test waters and to dry the pipeline.