Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Upstream
Oil Recovery Prediction for Polymer Flood Field Test of Heavy Oil on Alaska North Slope Via Machine Assisted Reservoir Simulation
Keith, Cody Douglas (University of Alaska Fairbanks) | Wang, Xindan (University of Alaska Fairbanks) | Zhang, Yin (University of Alaska Fairbanks) | Dandekar, Abhijit Y (University of Alaska Fairbanks) | Ning, Samson (Reservoir Experts, LLC / Hilcorp Alaska, LLC) | Wang, Dongmei (University of North Dakota)
Abstract The first ever polymer flood field pilot to enhance the recovery of heavy oils on the Alaska North Slope is ongoing. This study constructs and calibrates a reservoir simulation model to predict the oil recovery performance of the pilot through machine-assisted reservoir simulation techniques. To replicate the early water breakthrough observed during waterflooding, transmissibility contrasts are introduced into the simulation model, forcing viscous fingering effects. In the ensuing polymer flood, these transmissibility contrasts are reduced to replicate the restoration of injection conformance during polymer flooding, as indicated by a significant decrease in water cut. Later, transmissibility contrasts are reinstated to replicate a water surge event observed in one of the producing wells during polymer flooding. This event may represent decreased injection conformance from fracture overextension; its anticipated occurrence in the other production well is included in the final forecast. The definition of polymer retention in the simulator incorporates the tailing effect reported in laboratory studies; this tailing effect is useful to the simultaneous history match of producing water cut and produced polymer concentration. The top 24 best-matched simulation models produced at each stage of the history matching process are used to forecast oil recovery. The final forecast clearly demonstrates that polymer flooding significantly increases the heavy oil production for this field pilot compared to waterflooding alone. This exercise displays that a simulation model is only valid for prediction if flow behavior in the reservoir remains consistent with that observed during the history matched period. Critically, this means that a simulation model calibrated for waterflooding may not fully capture the benefits of an enhanced oil recovery process such as polymer flooding. Therefore, caution is recommended in using basic waterflood simulation models to scope potential enhanced oil recovery projects.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- 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)
- North America > United States > Alaska > North Slope Basin > Umiat-Gubik Area > Umiat Field > Tuluvak Formation (0.99)
- (10 more...)
Energy Efficient Steam-Based Hybrid Technologies: Modeling Approach of Laboratory Experiments
Pérez, Romel Antonio (Ecopetrol S.A.) | García, Hugo Alejandro (Ecopetrol S.A.) | Gutiérrez, Dubert (AnBound Energy Inc.) | Rodríguez, Hector Arnoldo (Ecopetrol S.A.) | Mehta, Sudarshan (University of Calgary) | Moore, Robert Gordon (University of Calgary) | Ursenbach, Matthew (University of Calgary) | Sequera-Dalton, Belenitza (University of Calgary) | Manrique, Eduardo Jose (Ecopetrol S.A.)
Abstract Colombia is evaluating different steam-based hybrid oil recovery technologies as a strategy to face current challenges in the development of heavy oil reservoirs. Oil price volatility, the need for an energy transition, and carbon footprint reduction are factors limiting the commercial deployment of conventional steam injection projects. Ecopetrol evaluates the hybrid steam methods at laboratory scale as one of the different options to overcome current constraints developing heavy oil resources. The ongoing experimental program is supported by numerical modeling as a prior step to upscale the results at the pilot-scale. This study aims to present history match results and describe the numerical modeling approach of hybrid steam experiments (50 mm diameter × 1.1 m long assembly) and compare it against the baseline steam injection simulation. The first hybrid test involved the injection of steam and flue gas considering consecutive floods that included a saturated steam flood (SSF), a flue gas slug injection, and a second saturated steam flood. The second test was a steam and solvent injection following the same experimental protocol (SSF + solvent + SSF). The variables matched included produced fluids, pressures, produced gas compositions, and temperature profiles. One important feature is that all three models use the same set of water-oil relative permeability curves obtained from an independent experiment. Also, it was assumed those curves are not a function of temperature, which simplifies the modeling and allows focusing on the physical mechanisms relevant to each experiment. For instance, for the hybrid steam-flue gas test, it was necessary to include an additional set of gas-oil relative permeability curves to account for the presence of the flue gas in the gas phase. The hybrid steam-solvent test was focused on modeling the mixing of the native oil with the injected solvent. The proposed workflow led to a good history match of all variables, particularly total produced fluids, temperature profiles, and injection pressures. Additional recommendations are provided based on laboratory observations to understand important mechanisms such as trapped gas, relative permeability hysteresis, and solvent characteristics. A new methodology to simulate hybrid steam methods is provided. The proposed numerical approach incorporates novel energy efficiency and carbon intensity indexes to guide the decision-making and identify recovery strategies driven by its efficiency and reduce carbon footprint. Both hybrid tests led to energy efficiency improvements and reduction in carbon intensity up to 20%. These indexes combined with experimental results will be key input parameters for designing and commissioning future pilot tests using numerical simulations at the field scale.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
Improved Oil Recovery Techniques and Their Role in Energy Efficiency and Reducing CO2 Footprint of Oil Production
Farajzadeh, R. (Shell Global Solutions International, Delft University of Technology) | Glasbergen, G. (Shell Global Solutions International) | Karpan, V. (Shell Development Oman) | Mjeni, R. (Petroleum Development Oman) | Boersma, D. (Shell Global Solutions International) | Eftekhari, A. A. (Technical University of Denmark) | Casquera García, A. (Delft University of Technology) | Bruining, J. (Delft University of Technology)
Abstract The energy intensity (and potentially CO2 intensity) of the production of hydrocarbons increases with the lifetime of the oil fields. This is related to the large volumes of gas and water that need to be handled for producing the oil. There are two potential methods to reduce CO2 emissions from the aging fields: (1) use a low-carbon energy source and/or (2) reduce the volumes of the non-hydrocarbon produced/injected fluids. The first solution requires detailed analysis considering the availability of the infrastructure and carbon tax/credit economics and is largely influenced by the cost of the CO2 capture technologies and renewable power. The second solution utilizes improved/enhanced oil recovery methods (I/EOR) aimed at injecting materials to increase the fraction of oil in the producers. In this paper, we use the production data from a field in the Middle East and show the high-level economics associated with switching the field operating energy demand to solar energy. We begin the analysis by first investigating the energy requirement of different stages in the life cycle of oil production and quantifying the CO2 emission and energy loss that can be avoided in each stage. We also utilize the concept of exergy to identify process steps that require lower energy quality and thus are the main targets for optimization. The analysis indicates that preventing CO2 emission is economically more attractive than utilizing mitigation methods, i.e., to capture the emitted CO2 and store it at later stages. Moreover, we show quantitatively how I/EOR techniques can be designed to reduce the CO2 intensity (kgCO2/bbl oil) of oil production. The energy efficiency of any oil production system depends on the injectant utilization factor, i.e., the volume of produced oil per mass or volume of the injectant.
- Asia > Middle East (0.49)
- North America > United States (0.46)
- Europe > United Kingdom (0.46)
Abstract In this study, molecular dynamics simulations have been performed to study the interfacial properties between water and oil with different mole fractions of CO2 under 8 MPa and 345 K. Simulation results show that with the increase of CO2 mole fraction, more CO2 got adsorbed in the water-oil interface region. Such CO2 increase weakened water and oil interactions at the interface, resulting in a decrease of the interfacial tension (IFT). Moreover, the water-oil IFT decreased significantly from 0 to 0.40 CO2 mole fractions. But the change was small for higher CO2 mole fractions of 0.40 to 0.80. From those calculations, we conclude that in the CO2-EOR, the volume of injected CO2 needs to be at least more than 0.4 mole fraction (to the oil) to achieve a decent reduction of the water-oil IFT. This study can provide a molecular level reference for implementing the CO2-EOR in the oil field under a low-pressure condition.
Summary Typical seawater depths for deep-water oil fields range from 1000m to 4000m. For these deep-water oil fields, the most popular and cost-effective technologies for increased oil recovery are water injection and subsea boosting with a multiphase helico-axial pump on the seabed. By installing a pump on the seabed, the well head pressure and thus the bottom hole pressure can be reduced, which will result in an increased well lifetime and thus an increased oil recovery. This contributes to a reduction in CAPEX per produced barrel and hence make the field development economically more interesting. Viscous multiphase production fluids occur in case of a viscous oil or in case of water-oil emulsions with a high apparent viscosity close to the inversion point. It is known that for viscous fluids the required power and size of the pump are significantly larger than for water-like products, such as low viscous oils. On top of this, due to the poor accuracy of the existing performance prediction models available in literature for viscous conditions, the pumps and the corresponding utility systems have to be significantly over-dimensioned to compensate for the uncertainties. This has a large negative impact on the CAPEX requirements for such field developments up to the point that it becomes economically unattractive to develop the field. For this reason, TotalEnergies (Operator), Sulzer (OEM) and TechnipFMC (EPC contractor) have launched real-size pump test campaigns in 2012 and 2014 with viscosities up to 3,000 cP in hot fluid and 10,000 cP in cold start-up conditions. The data obtained from those measurement campaigns have been used to develop a performance prediction model, which allows for accurate sizing of the pumps and corresponding topside utility system. This model allows for a reduction of the uncertainties and risks related to subsea boosting for viscous deep-water field developments and related to this the overall CAPEX requirements. This enables subsea boosting as a viable solution for increased oil recovery for deep-water fields with viscous multiphase fluids. This paper presents the test campaign and acquired measurement data. It explains how the effect of viscosity is modeled. It illustrates the match between the pump performance prediction model and the viscous multiphase test data. This allows for a reduction of the uncertainties and thus a more accurate pump selection.
Abstract Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome. CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping, dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geological traps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden. Maximizing storage while minimizing overburden stress in the near term depends on residual trapping in the swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiency and capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foam applications. Foam increases both sweep efficiency and residual gas saturation in the region swept. Both properties reduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foam generation, better injectivity, and better prospects for long-distance foam propagation at low pressure gradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil, as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency while reducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helps equalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reduces gravity segregation of CO2. Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, either through pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-design strategy. We review foam field trials for EOR and the state of the art from laboratory and modeling research on CO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Oklahoma (0.68)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (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)
- (43 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
A Novel Gas Dispersible Foam Technology Can Improve the Efficiency of Gas Injection Processes for IOR-EOR Operations in Unconventional Reservoirs
Díez, Kelly (Gastim Technologies) | Ocampo, Alonso (Gastim Technologies) | Restrepo, Alejandro (Gastim Technologies) | Patiño, Jonny (Gastim Technologies) | Rayo, Juan (Gastim Technologies) | Ayala, Diego (Gastim Technologies) | Rueda, Luis (Gastim Technologies)
Abstract Gas injection has become one of the most investigated methods for enhanced oil recovery in unconventional reservoirs. Nonetheless, the presence of natural and induced fractures negatively impacts the gas injection efficiency due to its channeling towards nearby wells or poor coverage in the treated area due to lack of conformance. To overcome these difficulties and boost the oil recovery process by gas injection, this work presents a novel gas dispersible foam technology to improve the sweep efficiency of gas injection in unconventional IOR/EOR projects. The development and evaluation of this technology has passed through a series of laboratory assurance stages that include fluids characterization, compatibility, and extensive coreflooding tests. A modelling approach is also presented, which was validated using lab and field data taken from the implementation of the technique in an extremely low porosity, tight and naturally fractured quartz-arenite gas condensate reservoir in Colombia. The workflow herein presented encompasses interdisciplinary components such as laboratory evaluation, reservoir modeling, treatment design, and wellsite setup and execution. Laboratory testing and inter-well field applications results, along with the development and testing of a phenomenological modelling approach, demonstrate that the gas dispersible foam injection can be a high potential technique for oil and/or condensate recovery in unconventional reservoirs given its proven ability to improve the deep reservoir gas conformance and avoid the lack of gas containment during gas injection IOR/EOR in unconventional plays. Lab results in a tight naturally fractured sample, suggest that the estimated incremental oil recovery was ~36% and the effective gas mobility reduction was ~45%. This technique also exhibited less chemical adsorption losses, which contributes to better chemical emplacement and longer durability. The main results of the field application, including a progressive decrease in gas injectivity at the gas injector, a consistent reduction in GOR with an associated oil increase at the influenced producer well, and a reported treatment durability of ~ 6 months, were all properly represented by the model. Each step of the workflow herein proposed not only assures the gas-based projects success, but also allows for smaller logistics footprint at the well location, along with less water consumption, which translates into cheaper and more efficient gas injection conformance operations.
Re-Injection of Produced Polymer in EOR Projects to Improve Economics and Reduce Carbon Footprint
Ghosh, Pinaki (SNF Holding Company) | Wilton, Ryan R (SNF Holding Company) | Bowers, Annalise (SNF Holding Company) | O’Brien, Thomas (SNF Holding Company) | Cao, Yu (SNF Holding Company) | Wilson, Clayton (SNF Holding Company) | Metidji, Mahmoud Ould (SNF SA) | Dupuis, Guillaume (SNF SA) | Ravikiran, Ravi (SNF Holding Company)
Abstract Chemical Enhanced Oil Recovery (cEOR) flooding is one of the more attractive methods to improve oil recovery. However, during times of instability in the oil market, cost of specialized chemicals and necessary facilities for alkali-surfactant-polymer (ASP) or surfactant-polymer (SP) make this technology very expensive and challenging to implement in the field. In majority of cases, polymer flooding alone has proven to be the most cost-effective solution that has resulted in attractive and predictable return on investment. In recent times, challenging economic environment has operators looking for added economic and sustainable savings. The possibility of re-injection of produced polymer to offset injection concentration requirements can lead to reduced cost and longer sustainability of oil recovery; thus, offering a subsequent reduction in produced water treatment and a reduced full-cycle carbon footprint. This innovative approach is subject to conditions experienced in the surface facilities, as well as in the reservoir. As part of this study, different polymer chemistries were investigated for their mobility control in porous media and comparative effect on oil recovery trends in presence of produced fluid containing residual polymer. The initial fluid-fluid testing and lab characterization results were validated against a mature field EOR project for reduction in polymer requirement to achieve target viscosity. Monophasic flow behavior experiments were performed in Bentheimer and Berea outcrop cores, while oil recovery experiments were performed in Bentheimer outcrops with different polymer solutions – freshly made and combinations with residual produced polymer. In addition, comparative injectivity experiments with field and lab prepared solutions were performed in Bentheimer outcrop cores. Based on field observations and lab measurements, a 10-15% reduction in fresh polymer loading could be achieved through the re-utilization of water containing residual polymer in these specific field conditions. Similar screen factor measurements were obtained with increasing concentration of residual polymer solution. This agreed with the monophasic injectivity experiments in both outcrop cores that resulted in similar resistance factors for fresh polymer and blends with produced water containing residual polymer solution. Oil recovery experiments also resulted in similar oil displacement behavior (approximately 30-40% OOIP after 0.5 PV waterflood) for fresh and blends with sheared polymer solutions, validating no loss in recovery potential, with the added benefit of 10-15% polymer loading reduction.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada (0.93)
- Europe (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Rock Type (0.46)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Lloydminster Field (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > P09C License > Horizon Field > Vlieland Sandstone Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Evaluation of Carbon Footprint for a Hydrocarbon Foam EOR Field Pilot
Castellanos Diaz, Orlando (The Dow Chemical Company) | Katiyar, Amit (The Dow Chemical Company) | Hassanzadeh, Armin (The Dow Chemical Company) | Crosley, Matt (The Dow Chemical Company) | Knight, Troy (The Dow Chemical Company) | Rozowski, Pete (The Dow Chemical Company)
Abstract EOR intervention methods, such as surfactant injection for in-situ foam as a conformance improvement, help increase energy efficiency of the EOR process. However, it is very important to have a calculation framework that identifies actual values to these energy efficiency benefits and contrast them with the energy requirements of making the EOR intervention methods work in the field. Such a calculation framework was introduced in this work with a life cycle thinking approach. To showcase the calculation methodology, a foam assisted gas-EOR process trial was used as an example of a successful EOR intervention technology, specifically a field pilot from a trial between Dow Chemical and MD America Energy (SPE 201199). Injection and production data, together with industry averages on electricity generation, gas compression, and water treatment, were utilized to calculate energy input into the process prior, during, and post-trial. Energy differences due to the foam technology deployment were translated into carbon footprint equivalence and contrasted with the carbon footprint of manufacturing and transporting the surfactant. A benefit-to-burden carbon footprint ratio of 21 was obtained, which means that for every carbon units emitted while producing the foaming agent 21 carbon units would be saved when implementing the technology as opposed to not implementing it. On a per barrel basis, the carbon footprint of the technology is reduced by more than 50% when using the foam additive than the baseline, even including the carbon footprint of making the material. The calculations also showed that the gas compression and separation steps dominate the energy inputs of the EOR intervention method.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.61)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
First Thermo-Responsive Polymer Field Evaluation in a High Temperature Reservoir of Golfo San Jorge, Argentina. Promising Results for Cost Optimization in a Polymer Project
Hryc, Maria Alejandra (SNF Argentina) | Renta, Daniela Verónica (SNF Argentina) | Dupuis, Guillaume (SNF SA) | Leblanc, Thierry (SNF SA) | Peyrebonne Bispe, Maria Eugenia (CAPEX) | Goldman, Mayra (CAPEX) | Villambrosa, Martin (CAPEX) | Fondevila Sancet, Gaston (CAPEX)
Abstract This paper presents the results obtained during the first thermo-responsive polymer field evaluation carried out in Pampa del Castillo – La Guitarra field located in Golfo San Jorge basin, Chubut province, Argentina. For the selected reservoir conditions, two thermo-responsive (TR) polymers with the same backbone and different moieties content (TR 1 and TR 2) were designed as alternatives to the conventional HPAM polymer currently injected in the field. TR polymers are aimed to be injected at low concentration and low viscosities under surface conditions and are characterized by an activation temperature. Below this temperature threshold, they behave like regular HPAMs whereas above it they behave like associative polymers. In contrast to HPAMs, higher resistance factors are obtained with increasing temperature beyond the activation threshold, which would be achieved at reservoir conditions. TR 1, TR 2 and a selected HPAM were injected in the same well and same layer, under the same conditions during a polymer injectivity test (PIT) in order to compare their performances. The evaluation was done in a multilayer, 80°C - temperature reservoir showing permeabilities around 20 mD. This reservoir had been waterflooded for 32 years before polymer injection started. The test was carried out using a compact polymer injection unit (PIUC) for 60 days involving TR 1, TR 2 and HPAM injection at different concentrations and flow rates, previously defined to target similar mobility reduction (Rm – also called Resistance Factor, ReF) according to coreflood experiences. Fall-off tests were run prior to, during and after polymer injection to assess changes in the well injectivity. Along with the operation, laboratory tests were carried out on site to monitor water and polymer solution parameters. TR 1 and TR 2 polymers showed good injectivity, stable rheological properties and good performance during the injection test at all concentration values and flow rates. Well head pressure (WHP) recorded with TR 2 was higher than with TR 1, in accordance with the number of thermo-responsive moieties in each polymer formulation. TR polymers demonstrated to be purely shear-thinning while HPAM showed shear-thickening behavior in near wellbore conditions. These results indicate promising cost reduction that can be achieved through a concentration cut-back of 67%, while sustaining similar resistance factors under reservoir conditions. The present article will elaborate on the first results of an injectivity test of thermo-responsive polymer technology conducted in Argentina.
- South America > Argentina > Patagonia (0.54)
- South America > Argentina > Chubut Province (0.54)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- South America > Argentina > Chubut > Golfo San Jorge Basin > Pampa Del Castillo - La Guitarra Field (0.99)