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Collaborating Authors
Results
Novel Application of Polyethylene Oxide Polymer for EOR from Oil-Wet Carbonates
Trine, Eric Brandon (Ultimate EOR Services, LLC) | Pope, Gary Arnold (Ultimate EOR Services, LLC) | Britton, Chris James (Ultimate EOR Services, LLC) | Dean, Robert Matthew (Ultimate EOR Services, LLC) | Driver, Jonathan William (Ultimate EOR Services, LLC)
Abstract The objective of this study was to test the performance of high-molecular weight polyethylene oxide (PEO) polymer in a low-permeability, oil-wet carbonate reservoir rock. Conventional HPAM polymers of similar molecular weight did not exhibit acceptable transport in the same rock, so PEO was explored as an alternative polymer. Viscosity, pressure drop across each section of the core, oil recovery, and polymer retention were measured. The PEO polymer showed good transport in the 23 mD reservoir carbonate core and reduced the residual saturation from 0.29 to 0.17. The reduction of residual oil saturation after polymer flooding using PEO was unexpected and potentially significant.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.88)
Abstract Water is accumulated near the fracture surface after fracturing, which will block oil flow out. The water blockage can be mitigated through the immediate well flow back or through shutting in the well before flow back. Which method is more effective? There are mixed results in the literature from field reports and experimental or simulation studies. This paper discussed the literature results and simulation data obtained from this study. It is found that the oil recovery mainly depends on the magnitude of pressure drawdown and the strength of imbibition. When the pressure drawdown is high, immediate flow back may lead to higher oil recovery than shutting in a well before flow back. When imbibition is strong, shutting in may be beneficial to enhance oil recovery through counter-current flow. Although many parameters of reservoir properties and operations may affect the shut-in effect, those parameters may be grouped into the pressure drawdown and imbibition strength. The parameters of matrix permeability, wettability, initial water saturation, and formation compressibility are discussed. Analysis and discussion of simulation data also suggest that the oil recovery is a linear function of pressure drawdown, but the relationship between oil recovery and capillary pressure is non-linear and more complex. The results and discussion from this study suggest that the immediate flow back may outperform the shut-in if a large pressure drawdown is applied. If a reservoir provides a strong imbibition condition, the shut-in may be beneficial. Surfactants may be chosen to enhance imbibition. The surfactants which alter the reservoir from oil-wet to water-wet may be preferred.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (10 more...)
Abstract During miscible gas injection for enhanced oil recovery, the composition of the fluids can change throughout the reservoir as the oil and gas phases develop miscibility. Measuring and modeling relative permeability as compositional regions are traversed creates many challenges. In simulators, the association of each phase with a relative permeability curve sometimes creates discontinuities when phases disappear across miscibility boundaries. Some newer relative permeability models attempt to resolve these issues by changing the standard "oil" and "gas" method of phase labeling and instead labeling phases according to a physical property that is continuous and tied to composition, most notably the fluid density or Gibbs free energy (GFE). Ideally, a relative permeability model will be based on experimental measurements. A handful of all relative permeability experiments focus on studying changes in relative permeability brought about by changes in fluid composition with increasing capillary number. However, there is also evidence to suggest that composition can impact relative permeability even at capillary numbers well below the capillary desaturation threshold. In this research, two-phase gas/oil core flood experiments were performed with ethane as the gas phase and equilibrated octane as the oil phase. Pressure was varied so that the composition (density and GFE) of the gas and oil were changing. The capillary numbers were kept low and constant to prevent capillary desaturation of the oil phase. The experiments were then repeated with an added residual brine phase to test the effect of composition with a third phase present. The results show that changing the density and GFE of the oil and gas phases in either two-phase or three-phase flow had no impact on the relative permeability curves. However, significant changes were observed when comparing two-phase to three-phase oil and gas relative permeabilities. When only gas and oil were flowing in the core, the oil phase formed a continuous layer on the pore surfaces. The addition of residual brine caused the oil to form droplets, reducing the relative permeability of both the oil and gas phases in the absence of a continuous layer of oil. These findings verify previous history-matched relative permeabilities in literature and show that the oil phase connectivity is more important than compositional parameters.
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.48)
Mobility Of Microemulsions: A New Method to Improve Understanding and Performances of Surfactant EOR
Rousseau, David (IFP Energies nouvelles - The EOR Alliance) | Le Gallo, Clémence (IFP Energies nouvelles - The EOR Alliance) | Wartenberg, Nicolas (Solvay - The EOR Alliance) | Courtaud, Tiphaine (Solvay - The EOR Alliance)
Abstract The mobility of Winsor III microemulsions, which can form in reservoirs when a surfactant formulation contacts oil, has become a critical parameter for feasibility evaluations of surfactant flooding EOR. The reason is that these bicontinous phases with low mobility are likely to impair the sweep efficiency of the remobilized oil. The common procedures to evaluate microemulsion's mobility are based on viscosity measurements. As they involve rheometers, namely pure shear flows, and conditions where microemulsions are separated from the water and oil phases they should remain equilibrated with, they are not satisfactory. We present a new method to directly determine the mobility of microemulsions at equilibrium and in-situ, namely when flowing in porous media. The method consists in preforming the Winsor III microemulsion in a buffer cell and then injecting it in a small sized core plug. The bicontinous phase stays at equilibrium because the oil and water phases, present in the buffer cell, remain in contact with it. The mobility is assessed through the resistance factor (or mobility reduction factor), relative to the water phase injected first. This observable accounts for both viscosity and potential permeability impairment effect. As it directly represents the reduction of the mobility of the water phase, it is representative of phenomena taking place in the reservoir. During a typical experiment, the same microemulsion is also injected in a capillary tube, in order to determine its viscosity in a pure shear flow. Winsor III microemulsions were injected in sandstone plugs of three different permeabilities (1700 to 45 mD), and in a 170 mD carbonate plug. The first outcomes are that the resistance factors in the porous media and capillary relative viscosities have a marked shear-thinning behavior but are always of the same order of magnitude. This indicates that the flow of microemulsions entails no or little permeability impairment. Based on the experimental determination of the porous media's shape factors, the resistance factors and capillary viscosity data were also plotted against the equivalent wall shear rate. For the highest permeability sandstone, the capillary and porous medium data scaled almost perfectly, showing that, in this case, the microemulsion's transport properties are that of an ideal non-Newtonian fluid. However, increasing deviations were observed when decreasing the sandstone permeability as well as for the carbonate porous medium. This suggests that microemulsions are strongly affected by the composite deformations taking place in complex microscopic pore structures. These outcomes show the importance of determining the microemulsion-induced resistance factor in representative conditions in order to forecast for the impact of microemulsion's mobility in reservoirs. Furthermore, the method proposed can be applied to investigate close to optimum conditions as well as to study the propagation of microemulsions.
- Research Report (1.00)
- Overview > Innovation (0.60)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Experimental and Simulation Based Interpretation of Characteristic Behavior During Forced and Spontaneous Imbibition in Strongly Water-Wet Sandstones
Andersen, Pål Østebø (Department of Energy Resources, University of Stavanger, 4021 Stavanger, Norway) | Salomonsen, Liva (Department of Energy Resources, University of Stavanger, 4021 Stavanger, Norway) | Sleveland, Dagfinn (Department of Energy and Petroleum Engineering, University of Stavanger, 4021 Stavanger, Norway)
Abstract In this work we investigate forced and spontaneous imbibition of water to displace oil from strongly water-wet Gray Berea (~130 mD) and Bentheimer (~1900 mD) sandstone core plugs. Two nonpolar, nonvolatile oils (n-heptane and Marcol-82) and their mixtures were used as non-wetting phase, giving oil viscosities between 0.4 and 31 cP between experiments. Brine (1 M NaCl) was used as wetting phase with viscosity 1.1 cP. Recovery was measured for both imbibition modes, and pressure drop was also measured during forced imbibition. Forced imbibition (five tests) was conducted with same viscosities at low and high injection rate using two different viscosities. 17 spontaneous imbibition experiments were performed at four different oil viscosities, and on the two rock types, including tests at same conditions. By varying the oil viscosity, injection rate and imbibition modes we measured the system's response to displacing oil by water under different conditions where both capillary and advective forces were allowed to dominate. Our hypothesis is that such a combination of experiments allows us to determine some characteristics of water-wet systems. Transient analytical solutions were derived accounting for low water mobility and inlet end effects, allowing theoretical predictions consistent with the observations. Full numerical simulations were also run to consistently match all the experimental observations. We find that, consistent with the literature, water has low mobility associated with its relative permeability. Thus, complete oil recovery was achieved at water breakthrough during the forced imbibition both at low and high oil viscosity tests. For the same reason, increasing oil viscosity by a factor of almost 100 did not increase the spontaneous imbibition time scale by more than 5 compared to the lowest oil viscosity. This was consistently matched by our models. Theoretical analysis indicates that pressure drop increases linearly with time until water breakthrough if capillary pressure is negligible and that the initial pressure drop correspond to the oil relative permeability end point. Positive capillary forces assist water in entering the core, and the pressure drop is reduced and possibly nonlinear with time. Using a high injection rate we could a linear trend more clear than at low rate, consistent with our predictions.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Implementation of a second Double Displacement Process (DDP2) has been evaluated for Yates Field Unit (YFU). A DDP2 Demonstration Area Project has been designed to test DDP2 in a mature, high recovery area of the field. A detailed, geologically based reservoir description was used to build a simulation model for the DDP2 pilot area to study the DDP process and evaluate DDP2 performance. Initial saturations and relative permeability curves were generated based on a capillary pressure based Saturation Height Function (SHF) study. The fracture system was simulated using a hybrid dual porosity/permeability system. A 9-component equation of state (EOS) was used to model the YFU fluid properties. Capillary pressure of imbibition is used to capture the effect of hysteresis and oil trapping in the zones invaded by the aquifer during primary depletion. The simulation model has been tuned against historical performance since 1927, focusing on the first DDP process (DDP1) implemented over 1992-2000. Matching historical production/injection, field pressure and fluid contacts data were the history matching objectives. The DDP2 pilot project will include lowering 31 Horizontal Drain Hole (HDH) lateral completions by 25 feet to lower the contacts. The tuned model has been used to generate flow streams for different forecasting scenarios utilizing the DDP2 process. Forecast results show incremental oil recovery by lowering the contacts by 25 feet during the DDP2 phase. This paper presents a comprehensive study of YFU DDP1 process and evaluation of the second DDP process by a 3D numerical simulation model. The simulation model is used to improve understanding of the complex Gas-Oil Gravity Drainage (GOGD) and Gas Assisted Gravity Drainage (GAGD), and provide forecasts for the DDP2 process. Success of the pilot will result in extending the field life another 10-20 years.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (28 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Modeling of Laboratory Gas Flooding in Tight Chalk with Different Non-Equilibrium Treatments
Mirazimi, Seyedamir (Technical University of Denmark) | Olsen, Dan (Geological Survey of Denmark and Greenland, GEUS) | Stenby, Erling Halfdan (Technical University of Denmark) | Yan, Wei (Technical University of Denmark)
Abstract This paper focuses on proper modeling of bypassed oil in tight chalk during gas injection, caused partly by the small-scale heterogeneity and the non-equilibrium contact especially in low permeable chalk. Conventional compositional simulators using the local equilibrium assumption tend to predict excessive vaporization of the residual oil. We present the laboratory gas flooding results in tight chalk and discuss how different non-equilibrium treatments can provide more realistic simulation results. Composite core flooding experiments with low-permeable tight chalk and natural gas were conducted at different pressures below the minimum miscibility pressure of the live oil used. The ECLIPSE compositional simulator E300, using an EoS model tuned with the swelling data, was used to history match the results. It was found that the simulation without considering non-equilibrium effects over-predicted the oil production in the late stage. Two methods were tested to avoid the excessive vaporization of oil: the Sorm method (excluding the residual oil from flash calculations) and the transport coefficients (alpha factors) method together with pseudo-relative permeability curves. Our results show that the sub-grid non-equilibrium effect is significant in tight chalk. Compositional simulation without considering this effect leads to unrestricted vaporization and over-prediction of the oil recovery in gas injection into tight chalk even for laboratory experiments. Both methods tested here are suitable for reproducing the flooding results, in particular, the residual oil in the late stage. For the experiments studied here, the Sorm method seems to show a better performance in maintaining no further mass transfer between the residual oil and gas after the ultimate recovery is reached, since it excludes the bypassed oil fraction from flash calculations and models the immobile saturation explicitly. For the alpha factors method, oil production keeps a slow increase at the late stage as long as gas is being injected. In addition, the use of pseudo-relative permeability method can lead to obtaining irrational trends in some cases. We therefore propose an alternative method by adjusting the alpha factors of the mobile components, which avoids the difficulties of modifying the relative permeability curves. This study contributes to the methodology on honoring the non-equilibrium effects and obtaining realistic residual oil saturation for gas injection in tight formation. The proposed method of adjusting the non-zero alpha factors can be used as an alternative to using pseudo-relative permeability, which avoids the possible drawbacks involved in this method.
- North America > United States > Texas (0.47)
- Europe > Denmark > North Sea (0.28)
- Europe > Norway > North Sea > Cromer Knoll Group > Tuxen Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5504/7 > Valdemar Field (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5504/11 > Valdemar Field (0.99)
Abstract The mineralization that occurs after CO2 injection into shale is one possible long-term solution considered for storage of this greenhouse gas. However, the pore structure and connectivity of rocks will be affected in the process of mineralization. The purpose of this paper is to determine the effect of mineralization on reservoir connectivity during CO2 capture and storage (CCS). This mineralization is investigated here experimentally by injecting radially carbonate water into reactors containing rock samples. The rock samples were taken out at different mineralization times (24h, 72h, 120h, 168h), and permeability and scanning electron microscopy (SEM) tests were performed on the rock samples. According to the images of the overall characteristics and intergranular distribution characteristics under scanning electron microscopy, Avizo and Matlab software were used to divide the threshold value of gray value and statistics of gray value distribution, respectively. By defining the pore proportion degree, gray value frequency distribution and dissolution intensity, the dynamic change of pore connectivity in the process of mineralization was quantitatively analyzed. According to the threshold segmentation calculation of gray value, different dissolution modes in different stages of carbonization process were observed, including surface dissolution and particle denudation. The gray values in different ranges are quantized to analyze the influence of different dissolution types on pore connectivity. The synergistic effect of surface dissolution and particle denudation has a positive effect on the mineralization. We demonstrate the existence of a critical reaction time for mineralization, above which reservoir pore connectivity gradually decreases. At the same time, we found that the changes of reservoir connectivity and surface corrosion strength have roughly the same trend. Finally, the decrease of permeability caused by the accumulation of dissolved particles will contribute to the formation of self-sealing phenomenon during CCS. In this paper, the dynamic change of pore connectivity caused by mineralization during CCS is defined for the first time by statistical analysis of gray value, and the synergistic effect between surface dissolution and particle denudation is quantified, and the existence of self-sealing effect is verified. The results are of great significance for CCS.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.61)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (2 more...)
Abstract Low recovery of fracturing water is partly due to fracturing fluid leak-off into formation and water trapping in matrix. In our previous studies (Soleiman Asl et al. 2019 and Yuan et al. 2019), we showed that using surfactant solutions in fracturing fluid can significantly enhance imbibition oil recovery. However, there is one critical question remained unanswered: What are the consequences of these additives on well performance during flowback and post-flowback processes? Can they block the pore-throats of rock matrix and induce formation damage? To answer this question, we develop and apply a comprehensive laboratory protocol on a tight core plug to simulate leak-off and flowback processes under reservoir pressure, with and without initial water saturation (Swi). We evaluate the possibility of pore-throat blockage by comparing pore-throat size distribution of the core plug and size distribution of the particles formed in a microemulsion (ME) solution. We also investigate the effects of Swi on effective oil permeability (ko) after the flowback process. The results of leak-off and flowback tests using tap water as the base case shows that ko after flowback is lower than that before the leak-off, mainly due to phase trapping. However, results of the tests using the ME solution show that ko after flowback is greater than ko before leak-off. This observation suggests that the leak-off of ME solution enhances regained oil relative permeability during flowback by reducing phase trapping and water blockage. When Swi = 0, the blockage of leaked-off fluid reduces ko during the flowback process. The mean size of self-assembled structures (referred to as "particles" here) formed by mixing the ME solution with water is around 10-20 nm. The MICP profile of the core sample shows that around 95% of pore throats are bigger than the size of formed particles, suggesting low chance of pore-throat blockage by the suspended particles.
- North America > Canada > Alberta (0.93)
- North America > United States (0.68)
- North America > Canada > British Columbia (0.68)
- Geology > Geological Subdiscipline (0.93)
- Geology > Mineral > Silicate (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
Abstract As part of studying miscible GI in Deep Water GoM, four key areas were identified that could pose risk or uncertainty to value delivery. These were: reservoir containment, injectivity, reservoir sweep and reservoir optimization. Top seal integrity, column capacity, fault seal risk and asphaltene formation risk were identified as key drivers underpinning containment risk. As pointed out by Abouie et al. (2018), deposited asphaltene on the rock causes wettability alteration. This, in turn, significantly changes the displacement dynamics in miscible gas floods by lowering the gas mobility, increasing the mixing length, and reducing the displacement and sweep efficiency. The industry has not conducted many experiments to quantify the impact of asphaltenes on reservoir and well performance under gas injection (GI) conditions. This paper discusses a novel laboratory testing for evaluating the asphaltene impact in a major oil field in GoM. The goals of the study were to: a) Define the Asphaltene Precipitation Envelope (APE) using blends of reservoir fluid and injection gas, and b) Measure permeability reduction due to asphaltene precipitation in a core under gas injection. To properly analyze GI impact, a full suite of fluid characterization were conducted including restoring oil samples, compositional analysis, constant composition expansion and differential vaporization. The miscibility conditions were defined through slim tube displacement tests. Then, gas solubility-swelling tests were conducted. This was followed by Asphaltene Onset Pressure (AOP) testing. The permeability impairment experiments were carried out in a long core. A unique procedure was developed to estimate the impact of asphaltene deposition on core permeability. Using a fully saturated core with the live oil and injection gas mixture, several depletion tests were repeated starting from a pressure above the AOP (9000 psi) down to a pressure just above the bubble point followed by reloading the core with the same mixture at 9000 psi. These tests were meant to mimic continuous flow of oil along the path of injected gas and thereby observe the accumulation of asphaltene on the rock surface. The test results indicated that during this cyclic asphaltene deposition process, the core permeability to the live mixture decreased in the first few cycles but appeared to stabilize after cycle 5. The deposited asphaltenes were analyzed further through Environmental Scanning Electron Miscroscopy (ESEM), and their deposition was confirmed by mass balance before and after the tests. Finally, a relationship was established between permeability reduction and asphaltene precipitation. The results from the asphaltene deposition experiment show that for the sample, fluids, and conditions used, permeability is impaired as asphaltene flocculates and begins to coat the grain surfaces. This impairment reaches a plateau and subsequent permeability measurements indicate that stability is being established at approximately 40 percent of the initial permeability. Distribution of asphaltene along the core was measured at the end by segmenting the core and conducting solvent extraction. A novel systematic approach was developed for characterizing the permeability impairment due to asphaltene deposition during a gas injection EOR process. Numerical modeling of these test results and using this model to forecast the magnitude of the permeability impairment to be expected in a reservoir setting during miscible gas injection is our recommendation.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.50)
- North America > United States > Gulf of Mexico > Gulf Coast Basin > Wilcox Trend Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)