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Collaborating Authors
Results
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...)
Abstract This paper summarizes BP's Alaskan viscous oil resource appraisal strategy to de-risk viscous oil resource progression with a goal to improve recovery factor by 10%. A key to recovery improvement is application of improved oil recovery/enhanced oil recovery (IOR/EOR) methods. However, even after detailed studies, moving to the next stage including field pilots is not always easy in the mature and remote Alaskan North Slope. The paper also covers BP's Alaskan viscous oil technology strategy, extraction technologies selection, simulation and analytical studies, laboratory studies, and field trials for various shortlisted methods. A comprehensive study strategy conducted for progressing chemical EOR processes is discussed. The paper also addresses the challenges of obtaining new core and fluid samples for laboratory studies and logistical and economic considerations for field trials due to location and weather conditions in this part of the world.
- North America > Canada (0.68)
- Europe > United Kingdom (0.66)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.28)
- Geology > Mineral (0.93)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- North America > United States > Alaska > Schrader Bluff Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- (8 more...)
ASP Experiments in Indiana Limestone using NaOH to Reduce Surfactant Retention
Maubert, M.. (The University of Texas at Austin) | Jith Liyanage, P.. (The University of Texas at Austin) | Pope, G.. (The University of Texas at Austin) | Upamali, N.. (The University of Texas at Austin) | Chang, L.. (The University of Texas at Austin) | Ren, G.. (Total E&P R&T) | Mateen, K.. (Total E&P R&T) | Ma, K.. (Total E&P R&T) | Bourdarot, G.. (Total E&P) | Morel, D.. (Total E&P)
Abstract Alkaline-surfactant-polymer (ASP) coreflood experiments using Indiana limestone were conducted to test the effectiveness of sodium hydroxide in reducing surfactant retention on limestones. Low concentrations of sodium hydroxide of only about 0.3 wt% increase the pH to about 12.6. The high pH reduces the adsorption of anionic surfactants by changing the surface charge of the limestone from positive to negative as well as having other favorable geochemical effects. Sodium carbonate could not be used in these experiments to increase the pH because the Indiana Limestone rock contained gypsum, which causes calcium carbonate to precipitate when it dissolves. Another advantage of sodium hydroxide is that much lower concentrations are needed compared to sodium carbonate because of its lower molecular weight. No adverse reactions between the sodium hydroxide and limestone were observed and the propagation of the pH in the corefloods was observed to be extremely favorable. The tertiary oil recovery was high and the surfactant retention using sodium hydroxide was low compared to experiments without alkali and compared to typical retention values reported in the literature for carbonates.
- North America > United States > Indiana (0.82)
- North America > United States > Oklahoma > Tulsa County > Tulsa (0.15)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.72)
Abstract The sustained lower oil price for the last three years has shifted tight oil industry interest from an intensive drilling and completion based approach to more cost effective methods aimed at maximizing rates and ultimate recovery from existing wells. In that framework, application of conventional EOR methods to unconventional tight oil well has gained momentum in the recent period, with theoretical and experimental evaluation of approaches ranking from water and CO2 flooding to huff'n puff with chemicals. For that purpose, usual EOR experiments used for conventional rock cannot always be applied due to the extremely low volumes and permeability of tight reservoir rocks. This can lead to inaccurate results or extremely long experimental times. Here, we present a novel method for rapidly evaluating oil production by EOR methods in micro-Darcy permeability reservoir rock, and apply it to evaluate various chemical EOR approaches for unconventional tight oil wells. Our method relies on a fast screening and a continuous NMR monitoring of fluid saturations during imbibition experiments at reservoir temperature in miniaturized plugs. This permits to evaluate oil and water saturations in the rock samples as a function of time without having to interrupt the experiment for carrying out measurements. We validate this method by evaluating recovery from 10 μD sandstones and carbonates during imbibition of LowIFT formulations with various chemical additives. Despite the extremely low permeability, oil production from plugs using various chemicals can be evaluated and compared in less than 72 hours. Our new protocol shall be of interest to all laboratories trying to adapt EOR techniques to unconventional reservoirs, by permitting a real-time accurate and quantitative evaluation of various EOR options. In addition, the data we generated using various chemical EOR techniques support the interest of using low-IFT inspired chemical EOR methods to improve the ultimate recovery from tight reservoirs.
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
- Europe > France > Paris Basin (0.99)
Core Scale Simulation of Spontaneous Solvent Imbibition from HPAM Gel
Andersen, Pål Østebø (Dept. of Energy Resources, University of Stavanger) | Lohne, Arild (The National IOR Centre of Norway, University of Stavanger) | Stavland, Arne (The National IOR Centre of Norway, University of Stavanger) | Hiorth, Aksel (Dept. of Energy Resources, University of Stavanger) | Brattekås, Bergit (Dept. of Energy Resources, University of Stavanger)
Abstract Capillary spontaneous imbibition of solvent (brine bound in gel) from formed polymer gel into an adjacent, oil-saturated porous medium was recently observed in laboratory experiments. Loss of solvent from the gel by spontaneous imbibition may influence the blocking capacity of the gel residing in a fracture, by decreasing the gel volume, and may contribute to gel failure, often observed in water-wet oil fields. Formed gel cannot enter significantly into porous rock, which has important implications for spontaneous imbibition: the gel particle network itself is not imbibed, and remains close to the rock matrix surface, while gel solvent can leave the gel and progress into the matrix due to capillary forces. Polymer gel is an inherently complex fluid and modelling of its behavior is, as such, complicated. Accurate description and quantification of gel properties and behaviour on the laboratory scale is, however, necessary to predict the performance of gel placed in an oil field, particularly in fractured formations. In this work, we present an original modelling approach, to simulate and interpret spontaneous solvent imbibition from Cr(III)-Acetate HPAM gel into oil-saturated chalk core plugs. A theory describing solvent flow within a gel network is detailed, and was implemented into an in-house simulator. Simulations of spontaneous imbibition from gel was performed, and compared to free spontaneous imbibition of water. A good overall match was achieved between experiments and simulations on the core scale, which validates the proposed gel model. All Faces Open (AFO) and Two Ends Open - Free Spontaneous Imbibition (TEOFSI) boundary conditions were used in the experiments, and formed the basis for simulation. Spontaneous imbibition occurs at the core end faces that are open to flow and exposed to gel (different for the two boundary conditions). The gel surrounding the core was discretized and included as a part of the total grid to capture transient behavior. The surrounding gel is treated as a compressible porous medium where the gel's polymer structure constitutes the matrix having constant solid volume while the gel porosity is a function of pore pressure. The gel permeability is modelled as function of gel porosity using a Kozeny-Carman approach. The flow equations for the gel and core domains were solved simultaneously by implementing the proposed description into the core scale simulator IORCoreSim. Two properties were identified to control the transport of water from gel into the adjacent matrix: the permeability and compressibility of the gel. The flow of water from the gel was observed in simulations to occur in a transient manner, driven by the coupled gradients in gel fluid pressure and gel porosity, where the gel porosity initially decreases in a layer close to the core surface due to reduced aqueous pressure. Gel porosity continued to decrease in layers away from the core surface; the propagation rate was controlled by two main gel parameters: (i) Gel compressibility controlled the pressure gradient within the gel network, and the amount of water transported from the outer part of the gel towards the core surface to balance the pore pressure. (ii) Gel permeability limited how fast water could flow within the gel at a given pressure gradient, thus increasing the time scale of the overall imbibition process.
- Europe (1.00)
- North America > United States (0.93)
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract CO2 emulsion/foam is a promising method for controlling the mobility and improving the volumetric sweep efficiency in CO2 enhanced oil recovery (CO2-EOR) process. Recently, amine surfactants attract the attention of the researchers as CO2 emulsifiers/foamers, because of their switchable property: the surfactants are nonionic and CO2 soluble at high pH, and are cationic and water soluble at low pH. However, the efficiency of the commercial switchable amine surfactants is usually suppressed at high salinity (> 200 g/L TDS) and temperature (> 100 °C). Thus, novel switchable alkyl-amine surfactants are designed in house based on the hydrophilic and CO2-philic balance for rapidly generating strong and stable CO2 emulsions at high salinity and high temperature. These novel surfactants are evaluated and compared to a commercial one with respect to the solubility in brine and CO2, and emulsifying ability in bulk and in porous media at high temperature, high pressure and high salinity. The novel surfactants show outstanding performance: soluble in 220 g/L NaCl brine at pH≤8 from room temperature to 120 °C, soluble in CO2 at relatively low pressure (91 bar) and high temperature (110 °C). The surfactants are thermally stable at 110 °C and pH=4 in the absence of O2. Strong CO2 emulsion/foam is observed in both bulk test and in silica sandpack with 0.2 (wt)% of the surfactant in brine. Additionally, the apparent viscosity of the CO2 emulsion/foam at 110 °C is significantly higher than that at lower temperatures. Comparing to the commercial surfactants, the CO2 emulsion/foam is stronger and generated faster by the novel surfactants. These novel surfactants can be synthesized using commercially available feeds and simple industrial processes. Thus, the novel surfactants are promising for generating the CO2 emulsion/foam, especially in the hot and salty carbonate reservoirs.
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
A New Thermally Stable Synthetic Polymer for Harsh Conditions of Middle East Reservoirs: Part II. NMR and Size Exclusion Chromatography to Assess Chemical and Structural Changes During Thermal Stability Tests
Rodriguez, L.. (SNF) | Antignard, S.. (SNF) | Giovannetti, B.. (SNF) | Dupuis, G.. (SNF) | Gaillard, N.. (SNF) | Jouenne, S.. (Total) | Bourdarot, G.. (Total) | Morel, D.. (Total) | Zaitoun, A.. (Poweltec) | Grassl, B.. (Pau University, IPREM)
Abstract Most Middle East fieds present harsh reservoir conditions (high temperature, high salinity, low permeability carbonates) for polymers used as EOR mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable. At temperatures above 60°C, acrylamide moieties hydrolyze to sodium acrylate which ultimately leads to precipitation and total viscosity loss. Thermal stability can be improved by incorporating monomers such as ATBS or NVP. In a previous paper, we reported the development of terpolymers where incorporation of NVP was shown to provide improved stability up to 120°C. Unfortunately, NVP increases the cost of the polymer and limits its molecular weight. Additionally, NVP also causes drifts in the polymers composition, thereby impairing injectivity in low permeability carbonate rocks. The price of the final product, to achieve a given viscosity, is approximately 3 times higher compared to conventional HPAM polymers and 2 to 2.5 times higher than SPAM polymers (sulfonated polyacrylamide). More recently, we reported the synthesis of NVP-free polymers incorporating different mol precentages of ATBS. The ATBS containing polymers are cheaper than the NVP polymers and enable dosage reductions of up to 50%, to obtain the same viscosity. Additionally, they outperformed the NVP polymers in terms of injectivity and thermal stability, as well as pushed the stability limits from 105-110°C up to 130°C and 140°C in brines withTDS of 230 g/L and 100 g/L respectively. In this study, we present new data for viscosity and thermal stability of NVP-free polymers optimized in terms of process and molecular weight. In particular, the thermal stability study was completed with NMR spectroscopy and Size Exclusion Chromatography (SEC) analysis to obtain information on the evolution of the chemistry and the molecular weight distribution of the polymers during long-term aging. NMR and SEC analysis reveal that the reduction of the viscosity during aging is due to an evolution of the polymer chemistry (conversion of acrylamide and ATBS units in acrylates) as well as chain scission. The incorporation of ATBS, into the polymer backbone, appears to slow down hydrolysis and limits the viscosity loss. There was no modification of the chemistry observed for the polymer having the highest level of ATBS and any viscosity loss observed is directly related to a decrease in molecular weight. The optimization of the NVP-free polymers redues the dosage by one third, making them very attractive from an economic standpoint. Both NMR and SEC techniques, have been shown to be efficient tools to understand the mechanism involved in viscosity changes for polymer solutions during long-term thermal aging.
- North America > United States (1.00)
- Europe (0.93)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.70)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- (5 more...)
Abstract Smart water and low salinity waterflooding has been established as an effective recovery method in carbonate reservoirs by demonstrating a significant incremental oil recoveries in secondary and tertiary modes compared to seawater injection. Therefore, understanding of multiphase flow phenomena in reservoir rocks is critical to optimize injected water formulations for substantial increase in oil recovery. Characterization of fluid-fluid and fluid-rock interactions have been extensively conducted at micro- and macroscopic scale, attempting to reveal the underlying mechanisms responsible for wettability alteration. Indeed, routine methods for assessing macro-wettability of fluids on rock surfaces (contact angle) include the sessile drop and captive bubble techniques. However, these two techniques can provide different contact angle depending on rock surface heterogeneities, roughness and drop size. Thus, contact angle measured at macroscale can only be used to characterize the average wettability and a direct visualization at nanoscale is needed to identify oil and brine distribution in the carbonate matrix and wettability state at the pore scale. The application of ion-beam milling techniques allows investigation of the porosity at the nanometer scale using scanning electron microscopy (SEM). Imaging of carbonate porosity by SEM of surfaces prepared by broad ion beam (BIB) and under cryogenic conditions allow to investigate preserved fluids inside the rock porosity and, combined with energy dispersive spectroscopy (EDS) identify crude oil and brine distributions and quantify carbonate-oil interfaces and wettability state. The experiments have been conducted on carbonate rock samples aged in crude oil and saturated with brines at high and reduced ionic strength. This study established an experimental protocol using Cryogenic high resolution broad ion beam (Cryo-BIB SEM) equipped with energy dispersive spectroscopy (EDS). The results show that ion-BIB milling provides a smooth surface area with large cross-section of few mm. High resolution imaging analysis allowed identification of the different phases, chemical mapping and distribution of oil, brine within the porous matrix. Segmentation of rock-oil-brine interface allowed an estimation of the in-situ contact angle and showed the effect of injected salinity brine on the 2D contact angle and more accurate description of the carbonate wettability at nanoscale.
- Europe (1.00)
- Asia > Middle East (1.00)
- North America > United States > California (0.28)
- Geology > Mineral (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.56)
Effect of Low Salinity Waterflooding on the Chemistry of the Produced Crude Oil
Collins, I. R. (BP Exploration Operating Co. Ltd.) | Couves, J. W. (BP Exploration Operating Co. Ltd.) | Hodges, M.. (BP Exploration Operating Co. Ltd.) | McBride, E. K. (BP Exploration Operating Co. Ltd.) | Pedersen, C. S. (BP Exploration Operating Co. Ltd.) | Salino, P. A. (BP Exploration Operating Co. Ltd.) | Webb, K. J. (BP Exploration Operating Co. Ltd.) | Wicking, C.. (BP Oil UK) | Zeng, H.. (BP North America)
Abstract Injecting low salinity water into a petroleum reservoir to improve oil recovery has been studied extensively over recent years as a low cost enhanced oil recovery (EOR) process. Extensive chemical analyses have been performed on the effluent water from low salinity waterflood experiments which reveal the extent of interaction between the injected brine, the oil and the rock matrix. However, there has been little work reported on the impact of the injected fluid composition on the nature and composition of the oil recovered. This paper details an investigation on how the waterflood medium affects the chemistry of the produced oil, which is important for understanding the mechanism by which the additional oil is released. Produced oil samples were analyzed using High Resolution Mass Spectrometry (HRMS) which essentially measures the mass of individual molecular species very precisely, which makes it possible to assign a unique elemental composition (e.g. carbon, hydrogen, oxygen, nitrogen and sulfur content) to each mass. Additionally, by careful control of the ionization procedure, it was possible to identify acidic and basic polar species, as well as neutral aromatic hydrocarbons. The data indicates that the composition of the produced oil changes during the reduced salinity waterflood, with an increase in the CxHyO2 species occurring. These molecular species, compared to the secondary high salinity flood, are released as the tertiary low salinity injection water passes through the core; they then decline towards the end of the waterflood. In contrast, there appears to be little change in aromaticity, sulfur and nitrogen containing species during the flood. The fact that the produced oil is enriched predominantly with CxHyO2 species is consistent with the multiple ion exchange and local pH rise mechanisms proposed previously.
- North America > United States > Oklahoma (0.29)
- North America > United States > California (0.28)
- Geology > Mineral > Silicate > Phyllosilicate (0.71)
- Geology > Geological Subdiscipline (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
Boosting Oil Recovery in Unconventional Resources Utilizing Wettability Altering Agents: Successful Translation from Laboratory to Field
Kazempour, Mahdi (Nalco-Champion, an Ecolab Company) | Kiani, Mojtaba (Nalco-Champion, an Ecolab Company) | Nguyen, Duy (Nalco-Champion, an Ecolab Company) | Salehi, Mehdi (Nalco-Champion, an Ecolab Company) | Bidhendi, Mehrnoosh Moradi (Nalco-Champion, an Ecolab Company) | Lantz, Mike (Nalco-Champion, an Ecolab Company)
Abstract In recent years, the United States (US) has experienced a resurrection in hydrocarbon recovery owing to the extraction of oil and gas from unconventional resources. Due to the ultra-low permeability nature of these reservoirs and their oil-wet characteristics, oil production declines are steep and oil recoveries remain very low (< 12% of OOIP). This challenge endures even with the assistance of hydraulic fracturing advancements and well spacing optimizations. The billions of barrels of remaining oil is a good target for chemical enhanced oil recovery (EOR) technologies. In this study, after comprehensive laboratory testing, a series of customized chemical formulations was developed to improve oil recovery under the challenging conditions of the Middle Bakken and Niobrara formations (temperature >110 °C, salinity>220,000 ppm, and hardness>15,000 ppm). To examine the performance of the selected formulation in the field-scale, a single well enhancement trial was carried out. A detailed review of the lab and field data (pre-and post- treatment) is discussed in this study. Oil rate decline analysis and numerical simulations were used to obtain more insight about the true effectiveness of the chemical treatments. The results of this field trial reveal that injecting a proper wettability altering agent can improve oil recovery from shale oil reservoirs by up to 25% of the estimated ultimate recovery (EUR). The results of numerical simulations also show that the additional oil recovered in this field trial cannot be achieved by either well shut-in or straight water injection. The lessons learned from this study provide practical information to optimize similar field trial designs leading to more profitable projects. The concepts and information here can be also translated to other unconventional basins and gas condensate or wet/dry gas reservoirs.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.36)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (40 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (5 more...)