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Rajapaksha, Suneth (University of Texas at Austin) | Britton, Chris (University of Texas at Austin) | McNeil, Robert I. (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Unomah, Michael (The University of Texas at Austin) | Kulawardana, Erandimala (University of Texas At Austin) | Upamali, Nadeeka (University of Texas At Austin) | Weerasooriya, Upali P. (University of Texas at Austin) | Pope, Gary A. (University of Texas At Austin)
Chemical EOR can be an extremely efficient enhanced oil recovery method when properly designed, but specialized laboratory tests must be done to tailor it to the specific reservoir fluids and minerals. The final step in the laboratory evaluation process is to test the chemicals in reservoir cores under reservoir conditions. Unfortunately, available reservoir cores are typically not in their native state. In particular, they are usually in a highly oxidized state (high Eh) compared to the oil formation. The oxidation state of the minerals affects the surfactants and polymers used for chemical EOR, for example, surfactant adsorption increases. Ferric ions may be present in cores containing iron minerals at high Eh that were originally ferrous ions at low Eh in the oil reservoir. Ferric ions can cause polymer degradation and poor polymer transport among other problems. In general to obtain valid test results such cores must be restored to reservoir conditions before core floods are done using surfactants, alkali and polymers. The restoration process becomes more difficult as the temperature, salinity and hardness increase. Sodium dithionite is a strong reducing agent, but is not stable at high temperature and will not tolerate high levels of calcium. It also reduces the pH below reservoir pH. We have investigated methods suitable for removing these ferric ions and restoring the core to reservoir condition. We have found that an aqueous solution of sodium dithionite, sodium bicarbonate and Na4EDTA was effective as a first step in the restoration process. The Na4EDTA chelates the iron and removes amorphous ferricions from the surface. We illustrate the complete restoration method with several core flood examples. The new restoration method dramatically improved polymer transport, reduced polymer and surfactant retention, and increased oil recovery. It is also important to restore the wettability of cores to their original condition. We also recommend the new procedure be evaluated for other types of core floods such as those used to test the low salinity process.
Abbaszadeh, Maghsood (Innovative Petrotech Solutions) | Kazemi Nia Korrani, Aboulghasem (Innovative Petrotech Solutions) | Lopez-Salinas, Jose Luis (Rice University) | Rodriguez-de La Garza, Fernando (Pemex E&P) | Villavicencio Pino, Antonio (PEMEX E&P) | Hirasaki, George (Rice University)
Practical application of foams for chemical and solvent EOR processes requires a representative and predictive model for foam flow and its mobility control characteristics. Many parameters such as surfactant concentration, shear rate, capillary number, oil saturation, and salinity affect foam flow behavior. Accordingly, different mechanistic and empirical foam models have been investigated in the literature and implemented in commercial simulators. Usually parameters in these models are tuned to match lab data for a particular foam-surfactant and oil system characteristics.
This paper presents process-based numerical simulations for modeling of foam-surfactant flow in a vertical sandpack column based on two sets of laboratory experimental data. The experimental setup, procedure, measurements and data analysis are discussed to provide apparent foam viscosity data for modeling. In the first lab tests, foam quality is constant and the total fluid velocity changes for shear thinning effect; while in the second tests, foam quality is varied at a fixed total velocity. The parametric matching of lab data is based on both fine-scale numerical simulations of the sandpack experiments as well as theoretical considerations of governing flow physics. The foam model is tuned to variable velocity foam flow of the first data set and then used to predict the second data set as consistency check. Based on this experimentally-tuned model, a validated foam model is constructed for use in field-scale commercial simulations of surfactant-foam flow in pilot testing of a naturally fractured reservoir. The model predictions for the second data set as well as the associated sensitivity analysis prove that our modeling approach is applicable for large scale predictions.
The results of this paper illustrate a novel experimental procedure, a creative data analysis scheme and a comprehensive methodology for developing a process-based mechanistic foam model. The presented methodology for matching lab data is unique as it includes varying both foam quality and foam velocity for shear thinning and foam dry-out phenomena. As such, this model is shown to include basics physics of foam flow in porous media for large-scale field applications.
Increased secondary and tertiary oil recovery by low salinity water flooding and spontaneous imbibition has attracted widespread interest as a low cost improved oil recovery method. Field applications that give increased recovery by only 2% OOIP are considered economically viable. Although the number of reported laboratory and field investigations is now approaching 200, no consistent conclusions have been reached as the circumstances under which recovery is improved. The detailed mechanisms of low salinity are not understood. Laboratory studies continue to provide a practical approach to investigation of mechanisms and screening of candidates for field application. Quantitative assessment is made of how well low salinity recovers oil by waterflooding and spontaneous imbibition as compared to standard recovery. Tests are supported by detailed petrophysical analysis for a wide range of sandstones and carbonates,
Development of laboratory screening procedures for screening candidate reservoirs for enhanced oil recovery by low salinity waterflooding and spontaneous imbibition
Results, Observations, and Conclusions
The effectiveness of improved recovery by waterflooding and spontaneous imbibition are reported for 29 sandstones and 7 carbonates. Test parameters that have high correlation with improved oil recovery by low salinity water are identified. Investigated variables include connate water composition, and secondary recovery vs. tertiary recovery. Results for reservoir cores are compared to tests on outcrop cores.
Low salinity waterflooding has moved to field-wide application. Identification and optimization of conditions under which oil recovery is improved by low salinity injection are key issues in field application. Features of conditions identified by laboratory tests that show high correlation with improved recovery provide confidence in selection of candidate reservoirs for pilot and field-wide testing.
Low salinity water flooding is gaining much of attention for its potential in increasing oil recovery, in spite of the debatable working mechanism for both sandstone (SS) and chalk. Various mechanisms have been suggested in literature.
The objective of this work is to address oil/brine/rock (COBR) interaction and deduce thermodynamically possible product of the interaction, then verify with the experimental results. The experiments were designed to have most of the flooding with LSW as a secondary recovery method following seawater (SSW). This is to mimic the situation in most oil fields, which gone through seawater flooding and to contribute to the debatable discussion on the rule of LSW to enhance oil recovery as secondary or primary fluid.
From previous work in our laboratory, sulfate and magnesium have been identified as active ions in the seawater in altering chalk wettability to more water wet; hence they were also tested as single ions water flooding and imbibing fluids for both SS and chalk. This approach has contributed to our understanding of the possible reactions that occurs due to COBR.
From the SS part of the experiments, the results show indications of ion exchange, mineral dissolution processes and rock weakening causing fine migration. Mineral dissolution and ion exchange are not unexpected in presence of mineral such as, in general, kaolinite. The experimental results confirmed the simulated reaction between LSW and kaolinite from the increase of the pH and the resulted ions. In addition, the increase of the pressure drop detected during the flooding, could be related to the fine migration in addition to visual observation.
From the work performed on chalk (done on two types), the results indicate fine detachment, which was enhanced in presence of Mg2+ ions as imbibing fluid at elevated temperature (70°C) for chalk. An increase of the pH was also observed for all flooding and spontaneous imbibition tests, especially with SO42- (for SS and chalk). In contrast to SS, chalk flooded with LSW showed reduction of pressure drop across the cores.
The capacitance resistance model (CRM) is a popular reservoir model for describing injector-producer connectivity using nonlinear regression techniques. The CRM model is widely used as a complement to real time reservoir analysis and improved oil recovery in water and CO2 floods. However, the current CRM model is based on a material balance of the total fluid and only the pressure propagation equation is considered. However, saturation changes are also important especially when the water cut is small. To overcome this limitation, this paper proposes a coupled CRM model based on two-phase flow by incorporating fractional flow theories.
In the coupled CRM model, we construct material balances on both total fluid and oil. Relative permeability is introduced to separate the effect of oil flow from the flow of total fluid. The Koval method is incorporated to estimate the dynamic pore volume. An IMPES scheme is used to update pressure and saturation equations at each time step. By semi-analytically coupling the pressure and saturation in a producer-based control volume and using constrained multivariate nonlinear regression, the new coupled model can quantify the inter-well connection and the average saturation. As a result, the coupled CRM model can be extended to the whole time frame of water and gas floods.
This new model was tested in heterogeneous synthetic fields and then applied to field cases. Both studies show that the connectivities and time constants obtained are reasonable and correspond well with field geology knowledge. The saturation profile also matches the simulation results. The coupled CRM model is also compared with current CRM model. The results indicate that the connectivities can be different. Further validation and prediction verified that the coupled model is more accurate to describe well connections.
By incorporating the saturation variations to reflect two-phase flow, the coupled CRM model successfully overcomes the limitation of previous version by extending it from being used only in mature floods to the whole life of water and gas floods. This work can lead to a more informed workflow of optimizing injection scheme, and ultimately serve the goal of improving oil recovery.
The Bakken reservoirs represent a large untapped resource of oil. One of the challenges is extracting these crude oils from their low-permeability formations at economic rates. These reservoirs contain multiple pay zones, including some with carbonate (dolomite) lithology. Recent common practice is to drill horizontal wells and perform a series of large, multi-stage hydraulic fracture treatments. The fractures penetrate deeply into the reservoir and promote more efficient drainage of the oil.
This situation suggests that a surfactant technology designed to enhance oil recovery from fractured carbonate formations is a fit for these typical Bakken cases with Middle Layer complex fractured lithology. The concept of this technology is to incorporate appropriate surfactant formulations at a low dosage in the well stimulation fluids. If properly designed, such additives in the fracture fluids will penetrate into the highly oil-saturated matrix or natural fracture region and accelerate the extraction of the oil in place by rapid imbibition. This extracted oil can readily move from the matrix into the propped fracture system for production. Another benefit of the additive is its engineered property to leave the matrix or nature fracture face water-wet, facilitating oil movement during production.
This paper presents a study of a series of such stimulation fluid additives developed for enhanced oil recovery. Over 10 of special customized product blends were evaluated in laboratory for their effectiveness in increasing recovery of Bakken crude oil samples. Tests included compatibility with formation brine, surface tension and interfacial tension, wettability alteration, emulsion tendency, recovery factors from spontaneous imbibition with crude oil and formation brine, and compatibility with proposed fracturing fluids. These results show that more than one of these products improve recovery of Bakken crude oil by spontaneous imbibition from both outcrop limestone cores and from Bakken core material. The best of these products is recommended for field application.
Description of the material
We conduct steady-state CO2-brine flow experiments in 2-foot-long and 2.8-inch-diameter Berea sandstone cores at 20 °C and 1500 psi. Four pressure taps drilled on a core allow both the total pressure drop and the pressure drop across five individual sections to be independently measured. Water saturation in situ is measured with Computerized Tomography x-ray scanning. The CO2 and brine relative permeabilities are directly calculated with Darcy’s law.
Accurate determinations of CO2-brine relative permeability are important for modeling potential CO2 storage. This two-phase relative permeability also helps understand and investigate unsteady-state CO2-brine-oil three-phase relative permeability, which is vital in estimating and designing CO2 injection to enhance oil recovery.
Results, Observations, and Conclusions
(1) The relative permeability to both brine and CO2 of the last section (downstream, 15-cm long) is significantly smaller than that of any of the middle three sections. This testifies that the capillary end effect makes the relative permeability under-measured at the end of a core sample. (2) The values of the middle three sections are very close to each other, which indicate the middle part of our core is free of capillary end effect. (3) The CO2 end point relative permeability is 0.4~0.8, which is much higher than recent published measurements. (4) The brine end point relative permeability during imbibition is about 0.08, which is close to literature data.
Significance of subject matter
The most common assumption for CO2-brine relative permeability is that it is likely to be similar to oil-brine relative permeability for water-wet rocks. But recent measurements of CO2-brine relative permeability have differed greatly from oil-brine relative permeability; particularly, the measurements show a very low CO2 end point relative permeability (kr,CO2=0.1~0.2) and a relatively high residual water saturation (Swr>0.4) ( Lee et al. 2010, Zuo et al. 2012, Akbarabadi et al. 2013 and etc.). We hypothesize that the differences are caused by large capillary end effects resulted from the very low CO2 viscosity. Our experiments have observed this capillary end effect and measured CO2-brine relative permeability data, which are free of capillary end effect and similar to oil-brine relative permeability.
Bourbiaux, Bernard (IFP Energies nouvelles) | Fourno, Andre (IFP Energies nouvelles) | Nguyen, Quang-Long (IFP Energies nouvelles) | Norrant, Francoise (IFP Energies nouvelles) | Robin, Michel (IFP Energies nouvelles) | Rosenberg, Elisabeth (IFP Energies nouvelles) | Argillier, Jean-Francois (IFP Energies nouvelles)
Among various ways to extend the lifetime of mature fields, chemical EOR processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR as the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. However, a wide variety of surfactants can now be considered for EOR, among which products that alter the matrix wettability. The present paper deals with that recovery strategy and compares it with other strategies based on viscous drive enhancement. Comparison is based on the physical and numerical interpretation of original representative experiments.
The kinetics of spontaneous imbibition of chemical solutions by oil-wet limestone plugs and mini-plugs has been quantified thanks to X-ray CT-scanning and RMN measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves could be inferred from in-situ fluid saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, representative drive conditions of a fractured reservoir were imposed between the end-faces of a plug, in order to account for the possibly-significant contribution of fracture viscous drive to matrix oil recovery.
These experiments were modelled numerically, with a simulation software that takes into account the multiple effects of surfactant presence on rock-fluids systems, including rock wettability modification and water-oil interfacial tension reduction. Model predictability of experiments was quite satisfactory without resorting to any arbitrary tuning. Sensitivity studies were also performed to assess the role of physical drive mechanisms and of physico-chemical parameters, in view of recovery kinetics optimization.
In summary, the present paper provides a first inedited quantitative description of chemical EOR processes in neutral to oil-wet fractured reservoirs. This work calls for further development in order to delimitate the conditions on chemical additives and recovery process implementation that satisfy economic viability.
Hassenkam, T. (Nano-Science Center, Department of Chemistry, University of Copenhagen) | Andersson, M. (Nano-Science Center, Department of Chemistry, University of Copenhagen) | Hilner, E. (Nano-Science Center, Department of Chemistry, University of Copenhagen) | Matthiesen, J. (Nano-Science Center, Department of Chemistry, University of Copenhagen) | Dobberschutz, S. (Nano-Science Center, Department of Chemistry, University of Copenhagen) | Dalby, K.N. (Nano-Science Center, Department of Chemistry, University of Copenhagen) | Bovet, N. (Nano-Science Center, Department of Chemistry, University of Copenhagen) | Stipp, S.L.S. (Nano-Science Center, Department of Chemistry, University of Copenhagen) | Salino, P. (BP Exploration Operating Company) | Reddick, C. (BP Exploration Operating Company) | Collins, I.R. (BP Exploration Operating Company)
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 12-16 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Core tests have demonstrated that decreasing the salinity of injection water can increase oil recovery. Although recovery is enhanced by simply decreasing salt content, optimising injection water salinty would offer a clear economic advantage for several reasons. Too low salinity risks swelling of the clays which would lead to permanent reservoir damage but evidence of effectiveness at moderate salinity would offer the opportunity to dispose of produced water. The goal is to define boundary conditions so injection water salinity is high enough to prevent reservoir damage and low enough to induce the low salinity effect while keeping costs and operational requirements at a minimum. Traditional core plug testing for optimising conditions has some limitations. Each test requires a fresh sample, core testing requires sophisticated and expensive equipment, and reliable core test data requires several months because cores must be cleaned, restored and aged before the tests can begin. It is also difficult to compare data from one core with results from another because no two cores are identical, making it difficult to distinguish between effects resulting from different conditions and effects resulting from different cores. Gathering statistics is limited by the time required for each test and the fact that core material is in short supply. Thus, our aim was to explore the possibility of a cheaper, faster alternative.
The existence of an optimum injection rate for wormhole propagation, and face dissolution at low injection rates during matrix acidizing are well established. However, little has been documented that describes how the presence of residual oil affects carbonate acidizing. This study demonstrates the impact of oil saturation on wormholing characteristics while acidizing field and outcrop cores under reservoir conditions (200°F). Knowledge of the effect of different saturation conditions on acid performance will contribute towards designing more effective acid treatments.
Coreflood experiments at flow rates ranging 0.5 to 20 cm3/min were performed to determine the optimum injection rate for wormhole propagation when acidizing homogeneous carbonate and dolomite reservoir cores, and low permeability Indiana limestone cores of dimensions 3, 6, and 20 in. length and 1.5 in. diameter. Absolute permeability of the cores ranged from 1 to 78 md. The study involved acidizing cores saturated with water, oil, and water flood residual oil using 15 wt% HCl. The viscosity of the crude oil used was 3.8 cP @ 200°F. CAT scans were used to characterize wormholes through the cores. The concentrations of the dissolved calcium and magnesium ions were measured using Inductively Coupled Plasma-OES and the effluent samples were titrated to determine the concentration of the acid.
HCl was effective in creating wormholes with minimal branches for cores with residual oil (Sor=0.4-0.5) at injection rates 0.5 to 20 cm3/min. Compared to brine saturated cores, water flood residual oil cores took lesser acid volume to break through. Besides, the wormholing efficiency of regular acid improved with increasing acid injection rates in the presence of residual oil. Cores with residual oil after water flood showed no face dissolution at low acid injection rates. This is evident from the fact that at low injection rate, brine saturated cores measured the maximum calcium concentration in the effluent samples while cores with residual oil the least. Conclusions from this work aids better designing of acid jobs by highlighting the impact of oil saturation on wormholing characteristics of acid while acidizing carbonate rocks.