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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)
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)
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)
Reaction Kinetics Determined from Core Flooding and Steady State Principles for Stevns Klint and Kansas Chalk Injected with MgCl2 Brine at Reservoir Temperature
Andersen, Pål Østebø (Department of Energy Resources, University of Stavanger, 4021 Norway) | Korsnes, Reidar Inge (Department of Energy and Petroleum Engineering, University of Stavanger, 4021 Norway) | Olsen, Andre Tvedt (Department of Energy Resources, University of Stavanger, 4021 Norway) | Bukkholm, Erik (Department of Energy Resources, University of Stavanger, 4021 Norway)
Abstract A methodology is presented for determining reaction kinetics from core flooding: A core is flooded with reactive brine at different compositions with injection rates varied systematically. Each combination is performed until steady state, when effluent concentrations no longer change significantly with time. Lower injection rate gives the brine more time to react. We also propose shut-in tests where brine reacts statically with the core a defined period and then is flushed out. The residence time and produced brine composition is compared with the flooding experiments. This design allows characterization of the reaction kinetics from a single core. Efficient modeling and matching of the experiments can be performed as the steady state data are directly comparable to equilibrating the injected brine gradually with time and does not require spatial and temporal modeling of the entire dynamic experiments. Each steady state data point represents different information that helps constrain parameter selection. The reaction kinetics can predict equilibrium states and time needed to reach equilibrium. Accounting for dispersion increases the complexity by needing to find a spatial distribution of coupled solutions and is recommended as a second step when a first estimate of the kinetics has been obtained. It is still much more efficient than simulating the full dynamic experiment. Experiments were performed injecting 0.0445 and 0.219 mol/L MgCl2 into Stevns Klint chalk from Denmark, and Kansas chalk from USA. The reaction kinetics of chalk are important as oil-bearing chalk reservoirs are chemically sensitive to injected seawater. The reactions can alter wettability and weaken rock strength which has implications for reservoir compaction, oil recovery and reservoir management. The temperature was 100 and 130°C (North Sea reservoir temperature). The rates during flooding were varied from 0.25 to 16 PV/d while shut-in tests provided equivalent rates down to 1/28 PV/d. The results showed that Ca ions were produced and Mg ions retained (associated with calcite dissolution and magnesite precipitation, respectively). This occurred in a substitution-like manner, where the gain of Ca was similar to the loss of Mg. A simple reaction kinetic model based on this substitution with three independent tuning parameters (rate coefficient, reaction order and equilibrium constant) was implemented together with advection to analytically calculate steady state effluent concentrations when injected composition, injection rate and reaction kinetic parameters were stated. By tuning reaction kinetic parameters, the experimental steady state data could be fitted efficiently. From data trends, the parameters were determined relatively accurate for each core. The roles of reaction parameters, pore velocity and dispersion were illustrated with sensitivity analyses. The steady state method allows computationally efficient matching even with complex reaction kinetics. Using a comprehensive geochemical description in the software PHREEQC, the kinetics of calcite and magnesite mineral reactions were determined by matching the steady state concentration changes as function of (residence) time. The simulator predicted close to identical production of Ca as loss of Mg. The geochemical software predicted much higher calcite solubility in MgCl2 than observed at 100 and 130°C for Stevns Klint and Kansas.
- Europe (1.00)
- North America > United States > Kansas (0.91)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.66)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > Laramie Basin > Niobrara Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)
Abstract This paper presents a new wettability alteration model based on surface complexation theory and an extensive experimental dataset. The objective is to provide a general correlation for contact angle calculation that (1) captures the main mechanisms that impact rock-brine-oil wettability and (2) minimizes the number of parameters used to tune with experimental data. We compile a set of 141 zeta-potential and contact-angle measurements from the literature. We study the oil/rock surface-complexation reactions and model the electrostatic behavior of each data point. We develop a new wettability model that estimates the contact angle and consists of five terms based on the Young-Laplace equation. We use the Nelder-Mead optimization algorithm to determine the model-parameter values that produce the best fit of experimental observations. The contact angle estimates produced by our model are also verified against those calculated by Extended-Derjaguin-Landau-Verwey-Overbeekand (EDLVO) theory and are validated using UTCOMP-IPhreeqc to simulate five limestone Amott tests from the literature. The Blind-testing test reveals that our model is predictive of the experimental data (R = 0.81, RMSE = 12.5). While reducing the tuning parameters by half, our model is comparable to and–in some cases–even superior to the EDLVO modeling in predicting the contact angle measurements. We argue that EDLVO modeling has 10+ parameters, and the individual errors associated with each parameter could lead to wrong predictions. Amott-test simulations show excellent agreement between the proposed wettability-alteration model and experimental data. The rock's initial wettability was measured to be strongly oil-wet, with a negative Amott index and recovery factor around 5%, corroborating the calculated contact angle of 160 degrees. The recovery factor increases to about 20-35% as the rock becomes more water-wet after interaction with engineered water (contact angle changes to 90-64 degrees). Further analysis indicates the proposed model's capability to capture significant wettability-alteration trends. For example, we report increased water-wetting as brine ionic strength decreases, depicting the low-salinity effect. In addition, our model resulted in better convergence in some of the simulated core floods compared to EDLVO modeling. We conclude that our physics-based and data-driven model is a practical and efficient approach to predict rock-brine-oil wettability.
- Geology > Geological Subdiscipline (1.00)
- Geology > Mineral (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- North America > United States > Texas (0.89)
- Europe > United Kingdom > North Sea (0.89)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (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 > Improved and Enhanced Recovery > Chemical flooding methods (0.67)
The Effect of Phase Distribution on Imbibition Mechanisms for Enhanced Oil Recovery in Tight Reservoirs
Wang, Mingyuan (The University of Texas at Austin) | Argüelles-Vivas, Francisco J. (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin)
Abstract The main objective of this research was to investigate the impact of initial water on the oil recovery from tight matrices through surfactant-enhanced water imbibition. Two flooding/soaking experiments using fractured tight cores with/without initial water were performed. The experimental results were analyzed by the material balance for components: oil, brine, and surfactant. The analysis resulted in a quantitative evaluation of the imbibed fraction of the injected components (brine and surfactant). Results show that the surfactant enhanced the brine imbibition into the matrix through wettability alteration. The initial efficiency of the surfactant imbibition increased when brine was initially present in the matrix. The imbibition of brine was more efficient with no initial water in the matrix. A possible reason is that the presence of initial water in the matrix was able to increase the initial efficiency of the surfactant imbibition; however, the increased amount of surfactant in the matrix lowered the interfacial tension between the aqueous and oleic phases; therefore, the efficiency of brine imbibition was reduced. Another possible reason is that capillary force was lower in the presence of initial water in the matrix, resulting in weaker imbibition of brine. Although the two cases showed different characteristics of the mass transfer through fracture/matrix interface, they resulted in similar values of final water saturation in the matrix. Hence, the surfactant injection was more efficient for a given amount of oil recovery when there was no initial water in the matrix.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.32)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
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 Classical waterflooding methods which rely on water displacing oil are not plausible in unconventional shale reservoirs because of the low permeability of such reservoirs because the pressure gradients required to push the water through the reservoir matrix rock is impractical. However, when the shale reservoir is stimulated via multistage hydraulic fracturing a large number of microfractures form which provides a preferred pathway when subsequently water is injected into the reservoir. If this water has low salinity compared to the salinity of the resident brine in the matrix pores, an osmotic pressure gradient establishes between microfractures and the matrix pores that would cause water to enter the matrix pores and pushing oil out. In oil-wet shale reservoirs, this osmotic pressure allows brine imbibition into the matrix that promotes counter-current flow of oil into the fractures. In our research, this phenomenon was studied via carefully designed osmotic imbibition experiments that used low- salinity brines. Furthermore, adding a simple surfactant, or a wettability altering chemical, not only could enhance imbibition of water into the matrix, it can also create a low-IFT environment that would break the oil droplets into smaller ones to facilitate oil movement out of the micro and macro fractures to enhance oil recovery from the matrix. To scale laboratory results and observations to the field conditions, a multi-component mass transport model that includes advective and diffusive transport of water molecules was developed and used to match experimental results. We will present the core imbibition and numerical modeling results that indicate that low salinity brine plus a dilute surfactant enhances oil production. This paper pertains to a research effort conducted to assess the potential of a new EOR method, which involves the use of a mixture of low-salinity brine and low-concentrations of a surfactant or wettability altering chemical. In what follows, we will present the core flooding and numerical modeling results pertaining to the research objective. The results are intended to be used as the basis for designing economic EOR field applications in unconventional shale reservoirs.
- North America > United States > Colorado (0.95)
- North America > United States > Texas (0.70)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (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)
Polymer Chemical Structure and its Impact on EOR Performance
Beteta, Alan (Heriot-Watt University) | Nurmi, Leena (Kemira Oyj) | Rosati, Louis (Kemira Chemicals Inc.) | Hanski, Sirkku (Kemira Oyj) | McIver, Katherine (Heriot-Watt University) | Sorbie, Kenneth (Heriot-Watt University) | Toivonen, Susanna (Kemira Oyj)
Abstract Polymer flooding is a mature EOR technology that has seen an increasing interest over the past decade. Co-polymers of Acrylamide (AMD) and Acrylic Acid (AA) have been the most prominent chemicals to be applied, whereas sulfonated polymers containing 2-Acrylamido-tertiary-butyl sulfonic acid (ATBS) have been used for higher temperature and/or salinity conditions. The objective of this study was to generate guidelines to aid in the selection of appropriate polyacrylamide chemistry for each field case. Our main focus was in sandstone fields operating at the upper end of AMD-AA temperature tolerance, where it needs to be decided whether sulfonation is required. The performance of the polymer throughout the whole residence time in the reservoir was considered since the macromolecule can undergo some changes over this period. Several key properties of nine distinct polymer species were investigated. The polymers consisted of AMD-AA co-polymers, AMD-ATBS co-polymers and AMD-AA-ATBS ter-polymers. The polymers were studied both in their original state as they would be during the injection (initial viscosity, initial adsorption and in-situ rheology) as well as in the state which they are expected to be in after the polymer has aged in the reservoir (i.e. in a different state of hydrolysis and corresponding viscosity retention and adsorption after ageing for various time periods). We note that the combination of viscosity retention and adsorption during the in-situ ageing process has not been typically investigated in previous literature, and this is a key novel feature of this work. Each of the above parameters has an impact on the effectiveness and the economic efficiency of a polymer flooding project. The content of ATBS was limited to 15 mol%. Buff Berea sandstone was applied in the static and dynamic adsorption experiments. The majority of the work was carried out in seawater at temperature, T = 58°C. Under these conditions AMD-AA samples showed maximum viscosity and lowest adsorption when the content of AA was moderate (20 mol%). When the AMD-AA polymers were aged at elevated temperature, the AA content steadily increased due to hydrolysis reactions. When the AA content was 30 mol% or higher, the viscosity started to decrease, and adsorption started to increase as the polymer was aged further. Thermal stability improved when ATBS was included in the polymer structure. In addition, sulfonated polyacrylamide samples showed increasing initial viscosity yields and decreasing initial adsorption with increasing ATBS content. For most of the samples, the maximum observed apparent in-situ viscosity increased when the bulk viscosity and relaxation time of the sample solution increased. The information generated in this study can be used to aid in the selection of the most optimal polyacrylamide chemistry for sandstone fields operating with moderate/high salinity brines at the upper end of AMD-AA temperature tolerance.
- North America > United States > Oklahoma (0.29)
- North America > United States > West Virginia (0.24)
- North America > United States > Pennsylvania (0.24)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Geology > Mineral > Silicate (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/25 > Greater Schiehallion Field > Schiehallion Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/20 > Greater Schiehallion Field > Schiehallion Field (0.99)
Modeling CO2 Partitioning at a Carbonate CO2-EOR Site: Permian Basin Field SACROC Unit
Hosseininoosheri, P.. (The University of Texas at Austin) | Hosseini, S. A. (The University of Texas at Austin) | Nunez-Lopez, V.. (The University of Texas at Austin) | Lake, L. W. (The University of Texas at Austin)
Abstract The relative partitioning of CO2 during and after CO2 injection in a CO2-EOR process is affected by several parameters. While many geological properties cannot be changed in a specific hydrocarbon (HC) reservoir, it could be shown that an intelligent selection of CO2 injection strategy improves both the incremental oil recovery and CO2 storage capacity and security. Therefore, we investigated and discussed the partitioning of CO2 among different phases (oil, gas, and brine) after two well-known CO2 inejction schemes using field-scale compositional reservoir flow modeling in the SACROC (Scurry Area Canyon Reef Operators Committee) unit, Permian Basin. First, we used a high-resolution geocellular model, which was constructed from wireline logs, seismic surveys, core data, and stratigraphic interpretation. As the initial distribution of fluids plays an important role in CO2 partitioning, a comprehensive pressure-production history matching of primary, secondary, and tertiary recovery was completed. The hysteresis model was used to calculate the amount of CO2 trapped as residual. CO2 solubility into brine was verified based on previous experiments. The model results showed a new understanding of relative CO2 partitioning in porous media after a CO2-EOR process. We compared the contribution of CO2 trapping mechanisms and the sweep efficiency of Walter-Alternating-Gas (WAG) and Continous-Gas-Injection (CGI). We found that WAG injection showed a significantly superior behaviour over CGI. WAG not only decreased the amount of mobile CO2 (structural trapping), but also resulted in a competitive incremental oil recovery in comparison with CGI. Thus, clearly WAG injection ispreferred as it strongly enhances CO2 storage efficiency and containment security. The present work provides valuable insights for optimizing oil production and CO2 storage in carbonate reservoirs like SACROC unit. In other words, this work helps decision makers to set storage goals based on optimized project risks.
- North America > United States > New Mexico (1.00)
- North America > United States > Texas > Scurry County (0.87)
- Geology > Geological Subdiscipline > Stratigraphy (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- 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)
- (26 more...)
- 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 > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)