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Conventional and unconventional hydrocarbons are likely to remain the main component of the energy mix needed to meet the growing global energy demand in the next 50 years. The worldwide production of crude oil could drop by nearly 40 million B/D by 2020 from existing projects, and an additional 25 million B/D of oil will need to be produced for the supply to keep pace with consumption. Scientific breakthroughs and technological innovations are needed, not only to secure supply of affordable hydrocarbons, but also to minimize the environmental impact of hydrocarbon recovery and utilization. The lifecycle of an oilfield is typically characterized by three main stages: production buildup, plateau production, and declining production. Sustaining the required production levels over the duration of the lifecycle requires a good understanding of and the ability to control the recovery mechanisms involved. For primary recovery (i.e., natural depletion of reservoir pressure), the lifecycle is generally short and the recovery factor does not exceed 20% in most cases.
Use of surfactants and gas lift in combination to suppress severe slugging were tested. Surfactants were able to suppress severe slugging for most of the cases, and gas lift helped significantly. The presence of slug flow in the riser of the sunken Deepwater Horizon could make a significant difference in financial penalties for BP in the wake of the Macondo incident, an expert said. Riser slugging can restrict production and cause problems for downstream equipment. This paper discusses a simplified modeling approach to control of riser slugging.
Oil and gas extraction using water has opened up new hydrocarbon resources. However they can produce four times more salty water byproduct than oil. Desalination in shale gas and polymer-flood EOR remain niche markets for lowering cost and improving production. Aker Solutions and FSubsea have agreed to a joint venture, named FASTSubsea, to help operators increase oil recovery. High-concentration polymer flooding can improve oil-displacement efficiency but separation of oil/water mixture becomes more difficult because of emulsification.
Al Kalbani, Munther Mohammed (Heriot-Watt University) | Jordan, Myles Martin (Champion X) | Mackay, Eric James (Heriot-Watt University) | Sorbie, Ken Stuart (Heriot-Watt University) | Nghiem, Long X. (Computer Modelling Group Ltd.)
Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the
Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options.
Results show that the
This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.
Nanotechnology is one of the modern techniques that can be used for enhancing the oil recovery. Enhanced oil recovery (EOR) is mainly used after oil production declination by chemically altering the injection water. However, it is very important to have an environmentally friendly method to enhance oil recovery. A possible method is to use nanofluids that include nanosilica-polymer (NFs) which contain mainly sandstone ingredients.
This research is mainly an experimental investigation of the usage of several nanofluids with silica particles for enhanced oil recovery. Nanofluid injection is performed in core plugs and the oil recovery is compared with the oil recovery obtained with synthetic sea water (SSW) injection. Both nanofluid and SSW are injected in secondary mode. Five cleaned and dried Berea sandstone cores were used in the core flooding experiments. First, secondary recovery was applied on all cores by SSW injection. Then the cores were re-cleaned and re-dryed to be prepared for the secondary recovery by using 4 different types of nanofluids with the same concentration of 0.1 wt% as NFs.
In this research, it was important to use exactly the same rock in both the SSW and nanofluid flooding to avoid any effect of pore structure on the oil recovery. The research showed that the best nanofluid contained nanoparticles of silica-alumina. This nanofluid gave the highest oil recovery and altered the wettability from water wet to strongly water wet due to the ionic interactions. The ultimate oil recovery was increased to 10.4% of OOIP (original oil in place) compared to SSW injection. In addition to investigating the quantitative effect of the use of several nanofluids with different nanoparticles sizes and surface modifications on oil recovery we also applied Scanning Electron Microscopy (SEM) to study pore blockage, log jamming, and emulsions between NFs and crude oil.
Zhang, Xuan (China University of Petroleum East China) | Zhang, Guicai (China University of Petroleum East China) | Ge, Jijiang (China University of Petroleum East China) | Wang, Yanqing (The University of Tulsa)
Foam could increase the apparent viscosity of carbon dioxide (CO 2) significantly and control the mobility. This work focused on the enhancement of CO 2 foam stability with adding modified silica nanoparticles, which effected by the concentration ratio, pH and salinity. The results demonstrated that the interaction between the nanoparticles and surfactants was effected by both salinity and pH, and the mixing solution of 0.5 wt% NPs and 0.2 wt% C1202 was colloidal stable in high salinity brine at pH4.5 and 80 C, while at high pH 6.5, the NPs will aggregate. Higher nanoparticles concentration with constant surfactant concentration would increase the solution colloidal stability due to lower density of surfactant adsorbing at nanoparticles surface. The interfacial tension between CO 2 and water dropped to around 6mN/m significantly with surfactant C1202 and adding nanoparticles has slight effect on interfacial tension. However, the compression modulus increased maximum 3 times obviously calculated by the decrease of interfacial tension in shrinking process, which proved that due to strong and irreversible nanoparticles adsorption. Moreover, the core flooding results confirmed that adding NPs results in more viscous foam generation to reduce the CO 2 mobility and the total oil recovery enhanced 17% comparing with water flooding. This mixing solution makes it possible to enhance CO 2 foam stability at low pH and given high salinity, which is important to reduce gas mobility in reservoir conditions and, eventually, enhance oil recovery.
Surfactant based foams are used as one of the most effective techniques in controlling gas mobility during gas injection processes. Foam reduces gas mobility in porous media by increasing the gas apparent viscosity and decreasing the gas relative permeability, and hence it helps in improving sweep efficiency. However, one of the critical encounters when using foam in reservoirs is the adsorption of the surfactant on the rock surface. The loss of surfactant to the rock surface will lead to destabilizing the foam and accelerating the collapse rate of foam films. The objective of this paper is to study the behavior of surfactant adsorption in carbonate.
The adsorption of various surfactants in contact with carbonate was evaluated. We compared two different techniques to evaluate the adsorption of surfactant components onto the rock surface. The first method is using a total organic carbon (TOC) analyzer to measure the carbon number in each surfactant over time after being in contact with rock. The second method is using UV-spectroscopy in which the light absorbance at a certain wavelength is measured. The measurements are then used to calculate the total surfactant adsorption onto the rock surface. This paper presents the adsorption behavior of each surfactant studied in detail.
The results obtained by the techniques were compared for two different surfactants. An amphoteric surfactant and an anionic surfactant were used in this study. Results illustrated that both surfactants were adsorbed by the rock minerals. Surfactant 1 showed a higher adsorption value than the surfactant 2. However, the two used techniques to measure the adsorption showed different adsorption values for both surfactants. Using TOC, surfactants 1 and 2 showed a total adsorption of 0.746 and 0.428 mg/grock, respectively. While, using UV-spectroscopy, surfactants 1 and 2 showed a total adsorption of 1.149 and 0.306 mg/grock, respectively.
Understanding the surfactant adsorption behavior is an essential step in the surfactant selection process. Selecting a surfactant with minimal loss to the rock surfaces will lead to keeping the generated foam stable for a longer time in the reservoir and therefore, result in having a higher sweep efficiency.
Neubauer, Elisabeth (OMV Exploration & Production GmbH) | Hincapie, Rafael E. (OMV Exploration & Production GmbH) | Borovina, Ante (OMV Exploration & Production GmbH) | Biernat, Magdalena (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH) | Ahmad, Yusra Khan (Nissan Chemical America Corporation)
This work examines the potential use of two different nanoparticle solutions for EOR applications. Combining the evaluation of fluid-fluid interactions and spontaneous imbibition experiments, we present a systematic workflow. The goal of the study was to enable the generation of predictive scenarios regarding the application of Nano-EOR in OMV's assets. Therefore, influence of high and low TAN crude oil, core mineralogy, composition of the nanofluid on wettability alteration and recovery were studied. Nanomaterials used in this work employ inorganic nano-sized particles in a colloidal particle dispersion. We evaluated two types; one utilizes surface-modified silicon dioxide nanoparticles, while the other employs a synergistic blend of solvent, surfactants and surface-modified silicon-dioxide nanoparticles. IFT experiments were performed using a spinning-drop tensiometer and results were compared at ~180 min of observation. Amott-Harvey experiments enabled investigating wettability alteration considering effects of crude-oil composition and core mineralogy (~5 and ~10% clay content).
Interfacial tension reduction was observed for both nanofluids. The blend yielded slightly lower values (~0.5- 0.6 mN/m) compared to the nanoparticles-only fluid (~0.8 mN/m), which is most likely related to the surfactant contained in the formulation. Amott-Harvey spontaneous imbibition experiments depicted clear wettability alterations for both nanofluids. Cores with ~5% clay content exhibited a water-wettish behavior, and additional recoveries using the nanofluids were up to 10%. In the cores containing ~10% clay, the nanoparticle-only fluid spontaneously imbibes to the rock matrix and quickly displaces large amounts of oil (~70% independently of the oil type that was used). Contrary, the blend yields higher recovery from the 10% clay cores, with the high TAN oil than with low TAN oil (57 ± 3 vs. 45 ± 1%). However, in 5% clay cores, faster imbibition was observed when the blend was used, which can be explained by a higher capillary pressure. A special case was observed in cores with 10% clay content (Keuper), where the baseline experiments using brine exhibited a high standard deviation. We attribute this behavior to the large mineralogical heterogeneity of the Keuper cores and the heterogeneous distribution of clays and mineralogical impurities. Both the blend and the surface-modified nanoparticles managed to restore a water-wet state, and additional promising recoveries were up to 65% in the case of strong oil-wetness.
Nano-EOR is an embryonic technology; hence, literature data is scarce on how oil composition and reservoir mineralogy could influence its use to obtain additional recovery and maximize benefits. Our systematic workflow, helps understanding the parameters that require detailed evaluation in order to forecast recoveries for field tests. The experimental synergies provide a good approach to evaluate fluid-fluid and rock-fluid interaction.
Open hole gravel packing (OHGP) is one of the primary completion techniques in sandstone reservoirs with sanding tendencies. As companies are becoming more experienced with these operations they are starting to explore the options for completing more challenging wells; including longer open holes and more tortuous trajectories. Conventional techniques have limits when it comes to the maximum length and angles that can be gravel packed based on a defined set of parameters. In order to ensure the success of the gravel packing operations in these challenging wells new techniques need to be adopted.
This paper includes a review of the methods that can be utilised to extend the operating limits of open hole gravel packs, so that they can be used in the long geosteered wells that are becoming more common in the North Sea. It includes a case review of the first well gravel packed in the North Sea using Ultra-Lightweight (ULW) proppant, which was also the first ever combined use of ULW proppant and diverter valves. These technologies were required due to the long interval length, 4,880ft, and high angle, maximum 103°. A history match of the gravel pack model was also performed to evaluate the performance of the ULW proppant during a long horizontal gravel pack.
Surfactant floods can attain high oil recovery if optimal conditions with ultralow interfacial tensions (IFT) are achieved in the reservoir. A recently developed equation-of-state (EoS) phase-behavior net-average-curvature (NAC) model based on the hydrophilic-lipophilic difference (HLD-NAC) has been shown to fit and predict phase-behavior data continuously throughout the Winsor I, II, III, and IV regions. The state-of-the-art for viscosity estimation, however, uses empirical nonpredictive based on of fits to salinity scans, even though other parameters change, such as the phase number and compositions. In this paper, we develop the first-of-its-kind microemulsion viscosity model that gives continuous viscosity estimates in composition space. This model is coupled to our existing HLD-NAC phase-behavior EoS.
The results show that experimentally measured viscosities in all Winsor regions (two- and three-phase) are a function of phase composition, temperature, pressure, salinity, and the equivalent alkane carbon number (EACN). More specifically, microemulsion viscosities associated with the three-phase invariant point have an M shape as formulation variables change, such as from a salinity scan. The location and magnitude of viscosity peaks in the M are predicted from two percolation thresholds after tuning to viscosity data. These percolation thresholds as well as other model parameters change linearly with EACN and brine salinity. We also show that the minimum viscosity in the M shape correlates linearly with EACN or the viscosity ratio. Other key parameters in the model are also shown to linearly correlate with the EACN and brine salinity. On the basis of these correlations, two- and three-phase microemulsion viscosities are determined in five-component space (surfactant, two brine components, and two oil components) independent of flash calculations. Phase compositions from the EoS flash calculations are entered into the viscosity model. Fits to experimental data are excellent, as well as viscosity predictions for salinity scans not used in the fitting process.