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Collaborating Authors
Results
Abstract Transient N2-foam flow experiments were conducted in a heterogeneous sandstone core to improve our understanding of how foam flows in these complex systems. An apparatus with an aluminum core holder and a medical x-ray CT scanner was built to measure the aqueous-phase saturation nondestructively. Pressure readings along the length of the core, were recorded using six pressure taps drilled into the core. We coinjected the foamer solution and the gas at the core's inlet and allowed foam generation to occur inside the core. Measurements of the aqueous-phase saturation and of the pressure at various times enabled us to track and analyze the transient foam behavior in the core. Three foam qualities were tested ranging from low quality (gas fractional flow) of 33% to high quality of 90%. Results show that gas initially drains the core and forms weak foam before crossing a permeability discontinuity present in the core. The travel distance from the inlet until the point of entrance into the permeability discontinuity was inversely proportional to the water content of the foam. Wetter foams required a shorter distance before the gas entered the low-permeability layer. Crossing the permeability discontinuity, the weak foam became stronger as evidenced by the drop in aqueous-phase saturation and the increase in the pressure gradient. Once strong foam was generated, it traveled to the outlet in a piston-like fashion. After it breaks through the outlet, a second front appears to be traveling backward toward the inlet against the direction of flow. Diversion to lower-permeability layers occurs during this second front movement. This observation was validated qualitatively by a simple pore network model that is equipped with the invasion percolation with memory algorithm. The results of the network show the diversion occurring once strong foam generates in the high-permeability zone and explain the discontinuous aqueous-phase saturation observed during the first foam front movement.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
Review of Offshore Chemical Flooding Field Applications and Lessons Learned
Han, Ming (Saudi Aramco) | Ayirala, Subhash (Saudi Aramco) | Al-Yousef, Ali (Saudi Aramco)
Abstract This paper presents an overview of both research advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in matured or maturing reservoirs. The advancements of offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, it also assesses the chemical formulations applied or studied and injection/production facilities required in the offshore environments. Main technical challenges are presented for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems. The technologies reviewed include polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full field applications. It is feasible to implement offshore polymer injection either on platform or FPSO system. It is recommended to implement polymer flooding at early stage of reservoir development in order to maximize the investment of offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue in offshore polymer flooding. There are also some interesting research findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials including the single well tracer tests on surfactant, alkaline-surfactant, surfactant-polymer in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low partially due to their complex interactions with subsurface fluids and lack of much interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant based chemical flooding processes for offshore applications.
- North America > United States (1.00)
- Africa > Angola (0.89)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.35)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth (0.28)
- Overview (1.00)
- Research Report > New Finding (0.48)
- Geology > Rock Type (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Block 5 > Al-Shaheen Field > Umm Er Radhuma Formation (0.99)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 305 > Angsi Field (0.99)
- (3 more...)
Abstract Conformance control via near-wellbore mechanical and chemical treatments is well established. However, for extreme heterogeneities, effective conformance control mandates deep treatments. Such deep treatments or diversion would sustain sweep enhancement far from wells, deep into the reservoir. Deep diversion is even more mandatory for enhanced oil recovery (EOR) to assure the expensive injectants optimally contact the remaining oil. In this paper, we comprehensively present efforts to research, develop, and trial a crosslinked-gel system for deep diversion. We started by reviewing conformance control options including crosslinked systems. The review supported the immaturity of deep conformance control. Various gel-based solutions, especially preformed particle gels (PPGs) and colloidal dispersed gels (CDGs), were proposed; however, diversion effects were not clearly illustrated. For crosslinked-gels, all systems exhibited fast gelation, something suitable for near-wellbore treatments. We then studied the key crosslinked systems. We characterized their behavior using rheometry, bottle tests, and single-phase corefloods. We assessed their potential through oil-displacement corefloods in artificially fractured cores with and without in-situ imaging. In-house studies, on key gel systems demonstrated the feasibility of gels to affect diversion and enhance recovery but corroborated the extreme challenge to design systems with delayed gelation. To assure representative gelation, we developed, and utilized a continuous bi-directional injection protocol to assess gelation times in-situ. From there, we collaboratively developed, and characterized a unique delayed-gelation formulation. The collaborative study addressed this challenge where systems with delayed gelation were developed. In-situ gelation time estimation confirmed this delayed gelation capacity. Further corefloods addressed the key uncertainties including injectivity losses, limited propagation, and ineffective blockage. Simulations were performed to assess the process feasibility.The simulation studies supported the utility of deep diversion treatments. Simulation also guided the initial design of a trial. We focused on the design of a practical field trial.For further derisking, the first trial was optimized to serve as a practical proof-of-concept. Taking into account economics, success measurement, flow assurance, and depth of placement, we diverged from a trial where we observe deep diversion (and infer delayed gelation and effective blockage) then converged into a trial where we infer deep diversion (by observing delayed gelation and effective blockage). With that, we screened candidates with a clear hierarchy of screening criteria. Through this program, and for the first-time in the industry, we demonstrate the potential utility and feasibility of a crosslinked-gel system for deep diversion applications. This potential is supported by comprehensive experimentation including novel in-situ estimation of gelation times. Finally, a consistent workflow to design a practical field trial is laid out. This, in terms of design considerations and hierarchal screening, is believed to be of extreme value to the practicing reservoir engineers.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
Abstract Foaming injected gas has the potential to overcome operational challenges encountered with pure gas injection. A mechanistic population balance model that integrates observed pore level events that are responsible for foam generation and coalescence in porous media was developed. The model is integrated in the AD-GPRS framework (Automatic Differentiation-General Purpose Research Simulator). Based on experimental pore-scale observations that show that the Roof snap-off geometric requirement for foam generation is affected due to the presence of residual oil in the pore, we upscale the pore-scale observations to the macroscale. We use experimental coreflood data from the literature to verify the performance of the model developed. The coreflood data are of two experiments that use the same core to perform a foam flood with and without the presence of oil. Pore-scale observations that show the effect of residual oil on the geometric Roof snap-off requirement translate into less germination sites at the macroscale. The generation constant used in the population balance model in the absence of residual oil reduces to one-fourth its original value when oil is present. The model developed was able to describe experimental data with good agreement both in the presence and absence of oil. In the presence of residual oil, all other foam parameters needed for the population balance model were fixed except the generation constant. The results demonstrate that the "hindered snap-off concept is able to describe foam flow when only residual oil is present.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- (2 more...)
Improved Amott Cell Procedure for Predictive Modeling of Oil Recovery Dynamics from Mixed-Wet Carbonates
Kaprielova, Ksenia (King Abdullah University of Science and Technology) | Yutkin, Maxim (King Abdullah University of Science and Technology) | Gmira, Ahmed (Saudi Aramco) | Ayirala, Subhash (Saudi Aramco) | Radke, Clayton (University of California, Berkeley) | Patzek, Tadeusz W. (King Abdullah University of Science and Technology)
Abstract Spontaneous counter-current imbibition in Amott cell experiments is a convenient laboratory method of studying oil recovery from oil-saturated rock samples in secondary or tertiary oil recovery by waterflood of adjustable composition. Classical Amott cell experiment estimates ultimate oil recovery. It is not designed, however, for studying the dynamics of oil recovery. In this work we identify a flaw in the classical Amott cell imbibition experiments that hinders the development of predictive recovery models for mixed-wet carbonates. We revise the standard Amott procedure in order to produce smoother experimental production curves, which then can be described by a mathematical model more accurately. We apply Generalized Extreme Value distribution to model the cumulative oil production. We start with the Amott imbibition experiments and scaling analysis for Indiana limestone core plugs saturated with mineral oil. The knowledge gained from this study will allow us to develop a predictive model of water-oil displacement for reservoir carbonate rock and crude oil recovery systems.
- North America > United States > California (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Indiana (0.25)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.94)
Fast Screening of LSW Brines Using QCM-D and Crude Oil-Brine Interface Analogs
Yutkin, M. P. (King Abdullah University of Science and Technology) | Kaprielova, K. M. (King Abdullah University of Science and Technology) | Kamireddy, S. (King Abdullah University of Science and Technology) | Gmira, A. (Saudi Aramco) | Ayirala, S. C. (Saudi Aramco) | Radke, C. J. (University of California โ Berkeley) | Patzek, T. W. (KAUST)
Abstract This work focuses on a potentially economic incremental oil-recovery process, where a brine amended with inexpensive salts (in contrast to expensive surfactants and other chemicals) is injected into a reservoir to increase oil production. Historically, this process received the name of low salinity waterflooding (LSW) although the salinity is not always low(er). Nevertheless, we keep using this terminology for historical reasons. The idea of LSW has been known for three decades, but to the best of our knowledge no specific brine recipes that guarantee success have been presented so far. The reasons hide in the problem's complexity, disagreements in the scientific community, and a race to publish rather than to understand the fundamental principles behind the process. In this paper, we present an experimental model system that captures many of the important fundamental features of the natural process of crude oil attachment to mineral surfaces, but at the same time decomposes this complex process into simpler parts that can be more precisely controlled and understood. We systematically investigate the first-order chemical interactions contributing to the well-known strong attachment of crude oil to minerals using SiO2 as a mineral for its surface chemistry simplicity. Our preliminary results suggest that magnesium and sulfate ions are potent in detaching amino/ammonium-based linkages of crude oil with a SiO2 surface. However, when used together in the form of MgSO4, they lose part of their activity to the formation of a MgSO4 ion pairs. We also find that sulfate-detachment propensity stems not from the interaction with prototype mineral surface, but rather from the interactions with the crude oil-brine interface analog. We continue the systematic study of the ion effects on crude oil detachment, with and more results following in the future.
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
Abstract Wettability alteration considered as the principal mechanism has attracted more attention for low salinity waterflooding effect. It was significantly affected by electrokinetic interactions, which occurred at the interfaces of rock/brine and crude oil/brine. The mineral impurities of natural carbonate releasing ions have an important impact on the electrokinetics, which could lead to wettability shift subsequently. In this study, the effect of dolomite and anhydrite as the main impurities in natural carbonate, which caused wettability alteration, was evaluated using triple-layer surface complexation and thermodynamic equilibrium models coupled with extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. The electrokinetics of crude oil and carbonate in brines were predicted by the triple-layer surface complexation model (TLM) based on zeta potential, while thermodynamic equilibrium model was mainly used for analyzing the carbonate impurities on wettability alteration. The equilibrium constants of reactions were determined by successfully fitting the calculated zeta potentials with measured ones for crude oil and carbonate in different solutions, which were validated for zeta potential prediction in smartwater. The disjoining pressure results show that there is a repulsion between crude oil and carbonate in Na2SO4 brine (Brine3) or smartwater (Brine4) equilibrating with calcite when comparing to that in MgCl2 (Brine1) and CaCl2 (Brine2), indicating the water-wet condition caused by the presence of sulphate ions. Moreover, the equilibrium of carbonate impurities with smartwater increases the repulsion between oil and carbonate. When the sulphate ion concentration in the adjusted smartwater exceeds a certain value, the effect of carbonate impurities on wettability alteration is not significant. Finally, the influence of smartwater pH on the interaction between oil and carbonate was evaluated with or without considering the equilibrium of carbonate impurities.
- North America > United States (0.68)
- Europe (0.46)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Sulfate (0.79)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.51)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
SmartWater Based Synergistic Technologies: A Next Recovery Frontier for Enhanced Oil Recovery
Ayirala, Subhash C. (Saudi Aramco) | AlSofi, Abdulkareem M. (Saudi Aramco) | AlYousef, Zuhair A. (Saudi Aramco) | Wang, Jinxun (Saudi Aramco) | Alsaud, Moataz O. Abu (Saudi Aramco) | AlYousef, Ali A. (Saudi Aramco)
Abstract In this work, the synergistic effects of SmartWater in polymer flooding, surfactant-polymer flooding, carbonated waterflooding, and foam assisted gas injection processes were explored. A suite of multiscale experimental data was analyzed to demonstrate and quantify the benefits of water chemistry synergies in these different enhanced oil recovery (EOR) methods. The multiscale experimental data analyzed comprised of polymer rheology, core floods, foam stability and rheology, besides evaluating the zeta potential results obtained from surface complexation modeling (SCM). SmartWater increased the oil recoveries by 5-7% in addition to reducing the polymer concentration requirements by one-third in polymer flooding. Synergizing SmartWater with surfactant-polymer flooding increased the oil recovery by 4% besides lowering the polymer and surfactant consumption by 50%. SmartWater has been found to synergistically combine with carbonated waterflooding to increase the CO2 dissolved volumes by 25-30% for effectively lowering the pH at both calcite/brine and crude oil/brine interfaces. The availability of more CO2 dissolved volumes in SmartWater can cause enhanced oil swelling, greater oil viscosity reduction, and increased wettability alteration through pH induced modification of surface charges for higher oil recovery. SmartWater increased the foam stabilities by 2-3 times, foam apparent viscosities by 1.5 times, and porous media foam pressure drops by 50% to ensure the propagation of more stable and viscous foams deeper into the reservoir for better mobility control. The findings of this study have a practical impact on how the industry can efficiently operate EOR projects. SmartWater-based synergistic technologies can reduce the costs due to lowered volume requirements of different EOR agents and they can also increase oil recoveries to result in more practical, efficient, and economical EOR projects in the field.
- Asia > Middle East (1.00)
- North America > United States > Oklahoma (0.15)
Abstract This paper demonstrates the effect of pore systems and mineralogy on imbibition capillary pressure (Pci) of carbonate rocks. A systematic workflow is developed and followed to ensure the data quality of Pci, minimize uncertainty in deriving the Pci from centrifuge tests, and analyze the data together with pore-size distribution from mercury injection capillary pressure (MICP) and mineralogy from Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN). The workflow starts with assessing the centrifuge production data for gravity-capillary equilibrium at each speed. Then the quality-checked data is used to produce six different Pci curves using the analytical and numerical models. The analytical and numerical solutions assess the variability in solutions for various rock types, and ultimately, lead to the selection of the most-representative Pci curve. Finally, the representative Pci curves of varying rock types are analyzed together with the MICP and QEMSCAN data to examine the change in Pci curves as a result of changes in the number and character of pore systems, dominant pore throat radii, and mineralogy. Findings from this study present insights into the impact of mineralogy and pore systems on the behavior of the Pci curves. From the mineralogy perspective, the presence of dolomite, microporous calcite, or rutile and anatase (TiO2) within the rock composition has a strong influence on the Pci behavior of carbonate rock. The data reveals that the contrast between the micropore and macropore systems of bi-modal carbonates has the strongest influence on Pci. We find that Pci can be clustered based on mineral content for bi-modal carbonate rocks and the degree of communication between micropore and macropore systems. The novel approach presented in this study links the MICP and QEMSCAN data to the imbibition process making the way toward a better dynamic rock typing.
- North America (0.93)
- Asia > Middle East (0.46)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.36)
Simulation of Advanced Waterflooding in Carbonates Using a Surface Complexation-Based Multiphase Transport Model
Abu-Al-Saud, Moataz (Saudi Aramco) | Al-Saleh, Salah (Saudi Aramco) | Ayirala, Subhash (Saudi Aramco) | Yousef, Ali (Saudi Aramco)
Abstract Understanding the injection water chemistry effect, in terms of both salinity and ionic composition, is becoming crucial to increase oil recovery from waterflooding in carbonate reservoirs. Various studies have shown that that surface charge alteration is the main mechanism behind favorable wettability changes toward water-wet conditions observed during the injection of controlled ionic composition water in carbonates. Therefore, the synergistic coupling between multiphase transport and electrokinetics of brine/calcite and brine/crude oil interfaces becomes important to optimize injection water compositions for enhanced oil recovery in carbonates. In this investigation, the electrokinetic interactions of brine and crude oil in carbonates are accounted for and coupled with the multiphase Darcy flow model. The electrokinetic interactions are parametrized by the zeta-potential values of brine/calcite and crude-oil/brine interfaces, which are determined using a Surface Complexation Model (SCM). The SCM zeta-potential parameters are computed based on the local concentration of aqueous ions that follow the transport equation. The relative permeability and capillary pressure curves are altered based on zeta potential shifts, which resembles the wettability alteration process. The SCM zeta potentials are compared with the experimental zeta-potential measurements, while the multiphase transport model coupled with geochemistry is validated through a comparative coreflood experimental data reported in the literature. The SCM results governed by specified surface geochemical reactions agreed well with zeta-potential measurements obtained at both calcite/brine and crude-oil/brine interfaces. The coupled geochemical SCM with multiphase transport model accurately matched both recovery and pressure drop data from forced imbibition tests reported by Yousef et al. (2011) in both secondary and tertiary modes. The generated relative permeability curves followed Craig's rules in shifting the wettability from oil-wet toward water-wet conditions for advanced waterflooding processes in carbonates. These results confirm the robustness of proposed model based on validated SCM electrokinetic interactions. The development of such a coupled geochemistry based multiphase transport model is an important step to simulate advanced waterflooding processes in carbonates at reservoir scale by taking into account of more representative physicochemical effects. The novelty of this work is that it validates the SCM results with experimental zeta-potential data for different injection water compositions. Also, the applicability of coupled SCM with a multiphase transport model is successfully demonstrated by history matching the experimental coreflood data. The developed model and new findings shed some light on the importance of lower salinity and controlled ionic composition during fluid flow and oil recovery in complex carbonate formations.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.70)
- Geology > Rock Type > Sedimentary Rock (0.68)