Gasser-Dorado, Julien (IFP Energies nouvelles) | Ayache, Simon Victor (IFP Energies nouvelles) | Lamoureux-Var, Violaine (IFP Energies nouvelles) | Preux, Christophe (IFP Energies nouvelles) | Michel, Pauline (IFP Energies nouvelles)
SAGD is commonly used as a thermal EOR method to produce heavy oil. However it suffers from the production of acid gases formed by aquathermolysis chemical reactions that occur between the steam, the sulfur-rich oil and the mineral matrix. The objectives of this paper are to take advantage of a comprehensive chemical model coupled to compositional thermal reservoir simulations to predict and understand the H2S production variation at surface according to the type of reservoir.
Thermal reservoir simulations coupled to both a SARA based 10-component / 5-reaction chemical model fully calibrated against laboratory data and a compositional PVT are used to simulate SAGD processes on heavy oil fields in Athabasca, Canada. Numerical results are then analyzed to provide a comprehensive analysis of the mechanisms leading to in-situ H2S generation and its production at wellheads based on compositional thermal simulations coupled to a fully laboratory calibrated SARA-based chemical model. Composition of the pre-steam, post-steam and produced oil are compared to understand the effect of the aquathermolysis reactions. The impact of heterogeneities on H2S production both in-situ and at surface can also be observed and explained, especially the variations in vertical permeability. Then simple reservoir models with two facies are used to further understand the impact of heterogeneities on H2S production at surface. Overall heterogeneous cases show important changes in the temperature distribution, fluid flows, reactions kinetics and steam chamber shape that lead to H2S production variations at surface. This detailed description of the involved mechanisms in acid gases production will allow operators to better forecast their H2S risks according to their reservoir properties.
Preux, Christophe (IFP Energies nouvelles) | Malinouskaya, Iryna (IFP Energies nouvelles) | Nguyen, Quang-Long (IFP Energies nouvelles) | Flauraud, Eric (IFP Energies nouvelles) | Ayache, Simon (IFP Energies nouvelles)
In order to improve the oil recovery factor, many oil companies employ surfactant in injected water. On one hand, the injection of surfactant influences the interfacial tension and to a lesser extent, the mobility reduction factor. On the other hand, the efficiency of the surfactant depends strongly on the salinity and temperature conditions. In order to optimize the surfactant injection procedure, the salinity and temperature effects are commonly studied through series of laboratory experiments. However, these types of experiments are often long and expensive. Therefore, engineers use numerical simulations. The present study addresses a numerical model, which allows to take into account the modifications of the interfacial tension (IFT) and the mobility reduction factor due to the salinity and temperature variations during the surfactant injection.
In this work, we propose a coupled numerical model based on five equations: i) two transport equations of water and oil phases modelized by the Darcy's law, ii) two transport equations for the surfactant and the salinity (the surfactant and the salinity are transported only in the water phase) iii) one energy conservation equation to take into account the thermal effect on surfactant flooding. The system of equations includes the salinity and the temperature impacts on the surfactant adsorption and thermal degradation, as well as the interfacial tension. Thus, this model allows improving the analysis of thermal corefloods or reservoir operations resulting from the surfactant injection.
The coupled model is used to reproduce laboratory experiments based on corefloods. We analyze the interaction phenomena between the surfactant, salinity and temperature. Then, we demonstrate a competition between two phenomena: the thermal effect on the viscosity of water on one hand, and the effect of surfactant on the mobility of water on the other hand. This study highlights the efficiency of numerical simulations for the analysis and choice of the surfactant applied to the given reservoir and well conditions.
Obviously, the knowledge of IFT and its dependence on surfactant concentration, salinity and temperature is not sufficient to understand all the physical mechanisms involved in a coreflood study. The phenomena are in fact extremely coupled, and the reservoir simulator coupling all these effects is found to be very helpful for engineers in order to take a good decision about the surfactant species to be used.
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.
Beunat, Virginie (IFP Energies nouvelles) | Pannacci, Nicolas (IFP Energies nouvelles) | Batot, Guillaume (IFP Energies nouvelles) | Gland, Nicolas (IFP Energies nouvelles) | Chevallier, Eloïse (SOLVAY) | Cuenca, Amandine (SOLVAY)
Foam processes aim to improve the efficiency of gas-based injection methods through gases mobility control. They have been successfully applied in various EOR contexts: CCUS through CO2-EOR, steam injection for heavy oil reservoirs, and also in fractured reservoirs. The success of such processes depends on multiple factors, among which the interactions between the surfactants, the oil and the rock, play a key role. The purpose of this study is to provide initial answers by focusing on the influence of wettability and oil saturation on the behavior of CO2-foam flows.
A new coreflooding set-up is designed for ‘mesoscopic’ cores (2.5 cm diameter) in order to conduct foam formulation screening and perform faster foam injection tests at reservoir conditions (up to 200 bar and 60 °C). This set-up was first validated by repeating experiments performed previously on classical corefloods with 4 cm diameter cores. Similar results in terms of mobility reduction were obtained for the same operating conditions with a considerable reduction of test duration.
All experiments were performed with Clashach sandstones cores having approximatively 16 % porosity and 600 mD permeability. Two gas compositions have been studied: (1) a dense supercritical CO2 (density of 638 kg/m3 at P = 160 bar, T = 60°C) and (2) a non-dense gas mixture of CO2 and CH4. For each gas composition, four foam injection tests were carried out: two on water-wet rock samples, two others on crude-aged core samples, and for both in the absence and in presence of oil. Anionic surfactant formulations and gas were co-injected with a gas fraction of 0.7. Foam rheology was assessed by measuring foam apparent viscosity through a scan of interstitial velocities.
All the tests performed in dense conditions have highlighted the generation of strong foams, which present shear-thinning rheological behavior; the apparent viscosity decreases as a power law of the interstitial velocity. An influence of the wettability is observed on the foam apparent viscosity, which drops off by 30 % in altered wettability rock samples. When samples were originally saturated with oil at Swi, the level of apparent viscosity remains globally unchanged but the kinetics of the initial formation of the foam is slower with oil than without.
Foam flooding experiments are sometimes carried out simply in the presence of oil without taking into account the influence of wettability, which appears to be as important, if not more, than the oil saturation itself. These results will hopely provide some guidance for future foam studies and raise awareness on the importance of these parameters.
In a process of enhanced oil recovery (polymer flooding), of well treatment (conformance control, water shut-off) or eventually any other process, the injection of several types of polymer solutions can be envisioned. Polymers considered could have different chemical structure, may not have been dissolved in the same water and may not necessarily be injected in a single and unique well. The same question appears in connection with a method where a mixture of two (or more) polymers would be intentionally injected. The few studies available involve mixtures of polymers in organic solvents.
We could not find a study dedicated to an injection of a blend of polymers in porous media. Only a theoretical paper by V.P. Budtov [
There are two opposite answers. In the first one, at the laboratory scale, chemical interactions on the rock surface are instantaneous ("first come, first adsorbed"). According to the other one, at the reservoir scale, exchanges have all the time necessary to occur and they take place in the direction of a preferential adsorption of the stronger mass or higher affinity polymer ("hierarchical model"). In this paper, we present a complete modeling and simulation of multi-polymer injection(s), based on physical data. The concepts of mobility reduction and adsorption are studied and validated through some test cases. In particular, the effect of multi-polymer injection(s) on adsorption is investigated. In the first part, we introduce the mathematical system and the method used to solve it. The second part addresses the modeling of different parameters such as mobility and permeability reduction and hierarchical adsorption based on experimental data. Then, we discuss some numerical experiments realized thanks to the in-house software PumaFlowTM to validate the model and study the effect of multi-polymer injection(s) on adsorption. Finally, we conclude with the benefit provided by such type of modeling and we present the perspectives of this work.
Ayagou, Martien Duvall Deffo (Institut de la Corrosion) | Mendibide, Christophe (Institut de la Corrosion) | Duret-Thual, Claude (Institut de la Corrosion) | Kittel, Jean. (IFP Energies nouvelles) | Ferrando, Nicolas (IFP Energies nouvelles) | Sutter, Eliane (Laboratoire Interfaces et Systèmes) | Tran, Thi Tuyet Mai (Laboratoire Interfaces et Systèmes) | Tribollet, Bernard (Laboratoire Interfaces et Systèmes)
This paper examines the influence of traces of oxygen on corrosion and hydrogen charging of steel in an H2S containing environment. It is well known that H2S promotes hydrogen entry into steels, that may result in many types of steel failures such as Hydrogen Induced Cracking (HIC), Sulfide Stress Cracking (SSC), and Stress-Oriented Hydrogen Induced Cracking (SOHIC). Since it is a huge concern for oil and gas industries, standard test methods have been developed and published as NACE technical methods (e.g. NACE TM0284 and NACE TM0177). Though it is recognized that oxygen pollution should be avoided during H2S cracking tests, there is still a lack of experimental data to illustrate the potential impacts of a small oxygen pollution.
The aim of the present study is to check if oxygen traces can modify the mechanisms of corrosion and hydrogen charging of steel in H2S containing medium. Experiments consisted of hydrogen permeation measurements through a thin pure iron membrane. They were performed at free potential circuit in order to ensure more realistic environmental conditions. The corrosion rate was also evaluated and test solutions analyzed.
Materials used in oil and gas industries can be exposed to sour environments containing hydrogen sulfide (H2S), which is corrosive and known to promote hydrogen entry into steels. This may lead to several types of steel failures such as Hydrogen Induced Cracking (HIC), Sulfide Stress Cracking (SSC), and Stress-Oriented Hydrogen Induced Cracking (SOHIC).
Corrosion and hydrogen embrittlement of steels in H2S containing environments has been studied for several decades. Standard test methods have been developed for the selection and the qualification of steels for use in H2S containing environments, such as NACE TM 0177 and TM 0284.1,2 These standards strongly recommend to avoid oxygen infiltration in test environments. For instance, it is stated that ‘obtaining and maintaining an environment with minimum dissolved O2 contamination is considered very important’. It is also mentioned that O2 contamination may induce an increase of the corrosion rate and reduce hydrogen evolution and hydrogen entry into the steel. However, it is also recognized that ‘systematic studies of the parameters affecting these phenomena have not been reported in the literature’.
The objective of this work was to bring new insights on Polymer Adsorbed Layers (PAL) in porous media. Irreversible permeability reductions and irreversible polymer retention were firstly determined versus polymer molecular weight, flow velocity and brine salinity and hardness. The presence of PAL was then evidenced by small angle neutrons scattering (SANS). This allowed proposing interpretations of permeability reduction in terms of PAL thickness and density.
This study focused on the adsorption of partially hydrolyzed polyacrylamide (HPAM) polymers on granular packs of silicon carbide (SiC). Polymer solutions were injected at fixed flow rate and concentration. Irreversible permeability reductions (Rk) were determined from changes in pressure drops and irreversible polymer retention (Г) from the difference of volume at breakthrough for two successive slugs. In-situ SANS experiments were performed under flow using the contrast matching technique: the pore space was filled with an H2O/D2O mixture with a scattering length density equal to that of the SiC. This resulted in a two-phase system whose scattering intensity was directly connected to the PAL (meso)structure.
Results showed an increase of Rk and of Г with salinity (0.2 to 80 g/L, with a stabilization trend towards high salinities) and molecular weight. When hardness was increased, Rk was not much affected but Г increased. The SANS experiments revealed a scattered intensity vs. wave vector q typical of PAL with self-similar concentration profile. From these results, it was possible to determine PAL hydrodynamic thicknesses of adsorbed layers (εH) using the Rk values and according to a simple capillary bundle model. εH and Г values were then combined to estimate the PAL density. The impact of salinity could hence be interpreted in view of classical charge screening effect observed for solutions of polyelectrolytes. The impact of molecular weight was found qualitatively consistent with the increase in radius of gyration. Regarding the impact of hardness, stable εH and increased Г translated in an increase of the PAL density: this could be due to the creation of bridges between polymer charged monomers and divalent cations. As for the impact of flow velocity, increases of Rk and hence of εH was generally observed. Such behavior is consistent with a change of conformation of PAL, from coiled to stretched.
This work stand as the first direct experimental evidence of "irreversible" PAL in three-dimensional porous media under flow. It also represents a consistent set of results summarizing the impact on PAL of parameters that are particularly relevant for field operations. The results and corresponding interpretations are meant to be used in reservoir simulation softwares to improve the predictability and economics of polymer flooding EOR.
Water management has always been an important part of production operation but for chemical EOR it becomes one of the critical elements as the whole water cycle needs to be analyzed and adapted to the process. In particular one key aspect that is generally neglected concerns the impact of EOR chemicals on the produced water cycle. After the chemical breakthrough, part of the EOR chemicals (polymers and/or surfactants) will be back-produced and can induce heat exchanger fouling and strongly impact oil/water separation and water treatment surface processes. All these drawbacks may lead to skewed forecasts on economic performance of EOR projects.
Some of the key challenges with produced water treatments, that facility engineers and operators will be facing when preparing a chemical EOR project, will be highlighted in this paper. A focus on some experimental results obtained within the DOLPHIN JIP – supported by 14 oil companies – will be presented. A specific laboratory methodology dedicated to the study of the impact of ASP-type chemicals on heat exchanger fouling, oil/water separation and water treatment efficiency and which mimic actual surface processes, was designed.
Results presented will illustrate the operational conditions that favor deposit on heat exchangers when polymer is back-produced. Impact of having polymers and/or surfactant within produced fluids on oil/water separation (kinetics of separation and quality of both oil and water phases) and water treatment processes efficiency (evaluated by monitoring the concentration of remaining oil in water as a function of time) will also be outlined.
This work emphasizes that water management is a major challenge for chemical EOR that needs an integrated approach and should be studied upfront. Laboratory workflows and procedures could help the de-risking of operations and try to mitigate separation issues that could advantageously be integrated into the design of chemical EOR project.
Whereas polymer flooding is now a proven method for heavy oil reservoirs, the use of surfactants is reported only in a limited number of cases and mostly in combination with alkali (ASP) to benefit from in-situ generated soaps. Operational issues such as scale formation, corrosion or logistics difficulties are often encountered. The objective of this work was to assess for the feasibility of alkaline-free surfactant-polymer (SP) processes for heavy oil reservoirs. Three "pseudo-synthetic" sandstone cases have been investigated for SP formulation design and performance evaluation through coreflood tests:
100 cP oil viscosity, 60°C, 800 mD and salinity 7.5 g/L TDS; 1400 cP oil viscosity, 35°C, 2 D and salinity 20 g/L TDS; 4500 cP oil viscosity, 50°C, 2-4 D and salinity 6.4 g/L TDS.
100 cP oil viscosity, 60°C, 800 mD and salinity 7.5 g/L TDS;
1400 cP oil viscosity, 35°C, 2 D and salinity 20 g/L TDS;
4500 cP oil viscosity, 50°C, 2-4 D and salinity 6.4 g/L TDS.
All experimental assays have been carried out on outcrop rock plugs but with dead oil samples from real reservoirs. SP formulations were successfully designed for the three cases with ultra-low IFT (<10−2 mN/m) at the target salinities and with good solubilities. For the 1400 and 4500 cP cases, SP tertiary oil recovery coreflood tests were carried out and led to high recoveries, namely above 90% of post-polymer flooding ROIP. For the 1400 cP case, a salinity gradient method was proven successful to mitigate adsorption. For the 100 cP case, injections at and below the optimal salinity were carried out with good results in both situations. To enable these experimental assays, new protocols had to be developed to contend with the specificities of heavy oils such as very long equilibrium times and difficulties to determine the oil production in corefloods. These exploratory investigations demonstrate that alkaline-free SP processes are feasible for heavy oil reservoirs and that field operations can be prepared using proper laboratory methods.
The exploitation of unconventional hydrocarbons requires innovative skills to allow better characterization of brittle reservoir zone. The Young's modulus is a measure of their brittleness and requires an accurate determination of the rock density which is well known only at the well locations. The multi-component inversion is a process that holds a great potential but requires a specific seismic survey using
Presentation Date: Tuesday, September 26, 2017
Start Time: 8:55 AM
Presentation Type: ORAL