Mitchell, Jonathan (Schlumberger) | Staniland, John (Schlumberger) | Wilson, Alex (Schlumberger) | Howe, Andrew (Schlumberger) | Clarke, Andrew (Schlumberger) | Fordham, Edmund J. (Schlumberger) | Edwards, John (Schlumberger) | Faber, Rien (Shell Global Solutions International B.V.) | Bouwmeester, Ron (Sarawak Shell Berhad)
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 A laboratory study on core plugs from a carbonate field confirmed the efficacy of an alkaline surfactant (AS) formulation at reservoir conditions. Continuous monitoring of remaining oil saturation (ROS) in short core plugs using spatially resolved nuclear magnetic resonance (NMR) can provide insights into the processes by which surfactants release post-water-flood remaining oil.
The McElroy field is one of the oldest waterflood fields producing from fractured carbonate reservoirs. The field has been producing since the 1920’s and started waterflooding in the 1950’s. It is obvious that the waterflood process plays an important role in improving oil recovery. However, due to the complex fractured carbonate reservoir setting, it is a big challenge for the waterflood management to attain the ultimate oil recovery. Geologically, the field is divided into four main areas and each area behaves differently, with the waterflood process influenced by the characteristics of the fractured reservoir. Understanding the waterflood mechanism in each area will help to develop an appropriate strategic waterflood plan. This study focuses on characterizing the differences between the waterflood performance in two areas of the field, the Low Permeability Area (LKA) and the Low Pressure Area (LPA).
The study used a plentiful well database of about 680 wells within the LKA and LPA to define the contrasting waterflood performance in these areas. The main characteristics of the waterflood in the LKA and LPA to be discussed in this study consist of:
- Oil production performance
- Water production performance
- Oil recovery performance
- Waterflood management - the challenges and optimization
The main objective of the study is to define the similarities and distinctions of the waterflood mechanism performance of these two different fractured reservoir areas. This study also recommends further approaches to improve recovery efficiency in the McElroy field. The analysis can be used as a reference for waterflood design process in green or brown fields exhibiting similar conditions.
Water chemistry with selective ionic content and composition in the injection water plays a critical role to impact on several oil recovery enhancement processes. Lower ionic strength waters with threshold salinities less than 5,000 ppm are desired for SmartWater flooding in sandstones. Low salinity water depleted in monovalents, but enriched in sulfates and divalents is suited for SmartWater flooding in carbonates. Polymer floods mandate different low salinity water lacking both monovalent and divalent ions to reduce polymer dosage and improve project economics. ASP floods require optimal salinity water without the hardness ions to enable utilization of alkali and certain temperature tolerant surfactants in the chemical formulation design. Lower salinity water is desired for carbonated water flooding to increase CO2 dissolved quantities for better incremental oil recovery. Lower salinity waters could turn out to be advantageous even for CO2 WAG where low salinity benefits outweigh the adverse CO2 solubility effects. Thermal floods require fresh and hardness free water to generate the steam using boilers.
Injection waters of optimized salinity, ionic content and composition not only work on their own, but can also synergistically combine with other EOR processes to result in higher incremental oil recoveries. Lower salinity waters have a beneficial effect in polymer, surfactant, dilute surfactant and carbonated water floods to yield better oil recoveries when compared to high salinity water. In this paper we first provide an overview on the benefits of tuning injection water salinity and composition in different IOR/EOR processes with selected examples and then propose a unique set of injection water chemistry requirement guidelines for IOR/EOR. The study findings also point out the need to develop “water chemistry” as a specialty discipline within EOR portfolio and advocate for better integration of this area with other key surface and subsurface related disciplines to effectively improve upon IOR/EOR upstream value chain.
Tang, Shanfa (Yangtze University) | Tian, Lei (Yangtze University) | Lu, Jun (The University of Texas at Austin) | Wang, Zhengxin (Institute of Exploration and Development) | Xie, Yunlong (Institute of Exploration and Development) | Yang, Xiaopei (Institute of Exploration and Development) | Lei, Xiaoyang (Yangtze University)
Shuanghe oilfield is a sandstone reservoir with a long history of waterflooding. The field has been polymer-flooded, and is now under surfactant/polymer flooding. Although SP flooding is near the end, the residual oil saturation is estimated to still be 46~50% OOIP. Therefore, it is desired to find an efficient method to recover more oil for future developments. In this paper, we presented a new high-temperature-resistant nitrogen foam system that gives a low oil/water interfacial tension and improves the sweep efficiency after SP flood.
The foam agent was prepared with unique surfactants and a high-temperature-resistant foam stabilizer. This foam formulation is able to lower the oil-water IFT to the order of 10-2mN/m and create stable foam at high temperature. Firstly, the concentration of the foam agent was determined by interfacial tension contour diagram. Then, the molecular weight and concentration of foam stabilizer was optimized by Ross-Miles method. Next, the properties of foam were measured at different temperatures, salinities, hardness, and aging time. The final foam formulation is 0.35 wt% foam agent and 0.1 wt% stabilizer, which shows a low IFT (5.31×10-2mN/m) and high foam stability index (>10000mL•min). Operating parameters including foam injection modes, gas liquid ratio, injecting slug size were investigated at reservoir conditions. The results reveal that, alternating injection of gas and solution is better than co-injection; the optimum gas-solution ratio is 1:1; the optimum foam injecting size is 0.4 pore-volumes; and the injection rate was optimized as well.
The foam flood performance was validated by comparing with other three EOR processes in a series of four oil displacement experiments. The four individual corefloods are foam, polymer, gel and SP floods, and they were all injected after water flood. Among these four corefloods, foam flood showed the best performance and highest oil recovery. An additional coreflood was also done to mimic the field processes. The core was first water-flooded, polymer-flooded and SP-flooded, and then the foam was injected. The results showed the foam flood can effectively recover residual oil after the previous chemical processes. All experimental results indicate this low-tension foam flooding could be a potential application in Shuanghe oilfield.
Surfactant-enhanced oil recovery (EOR) in fracture-dominated naturally fractured reservoirs and very low-permeability Bakken type reservoirs are less known. Therefore, to predict their performance, improvement of the reservoir simulation tools is necessary to account for the fluid flow mechanisms as much as possible.
We present a dual-porosity numerical simulation model and algorithm (improved model) in which matrix-fracture fluid transfer function was improved by implementing a proper viscous displacement mechanism. This mechanism was added to the existed fluid expansion, gravity drainage, and capillary pressure mechanisms. Current dual-porosity reservoir simulators generally do not account for the viscous displacement mechanism. To validate both the accuracy and efficacy of the improved model, results were compared with the results from a variable permeability-porosity, single-continuum, fine-grid model (fine-grid model).
Simulation results of improved model were in agreement with the results of the fine-grid model as the reference case. In a one-dimensional numerical model, water flood cumulative oil production increased about 5% compared to the conventional dual-porosity model. Also, incremental oil production increased over 5% for 1 wt% surfactant concentration. In water flood stage the matrix grid oil production rate started at 0.25 bbl/day in improved model compared to 0.053 bbl/day in conventional dual-porosity model. This amount was 0.124 bbl/day against the 0.03 bbl/day at the start of chemical injection. Similar results were obtained in a 2-D numerical model. Improved model was computationally very efficient and it was much faster than the computation time of fine-grid model.
For a practical application, the improved model was used to design and assess the viability of an EOR pilot-test using a single-well, multiple-completion protocol in a fractured carbonate reservoir. This reservoir has a matrix permeability of 10 md and matrix porosity of 0.05, and fracture permeability of 10000 md. Similar result was obtained using improved and fine-grid models. Also sensitivity on various fracture spacing of 5 to 20 ft was performed. As a result, the smaller the fracture spacing is the higher the effect of viscous displacement.
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)
Waterflood core tests have clearly shown that decreasing the salinity of the injection water increases oil recovery. Despite the enhanced oil recovery, however, it is important to optimise the salinity of the injection water. There are several reasons for this. First, clays present in the reservoir can swell if too low a salinity water is injected. This can severely reduce injectivity. Secondly, blending produced water into the low salinity water injection stream provides a means to dispose of the produced water. Overall the salinity of the injection water must be high enough to prevent reservoir damage, but low enough to induce the low salinity effect. The use of waterflood core plug tests for optimising injection water salinity is not ideal, however. Such tests require homogeneous, uncontaminated samples and take a considerable time to complete (several months). Moreover, the tests require core material which is often in short supply. Therefore, a cheaper, faster alternative would provide a significant advantage.
We have developed a method that employs atomic force microscopy (AFM) to explore the relationship between the wettability response of a rock and the applied water salinity. We functionalise AFM tips with organic molecules and use them to represent tiny oil droplets of non-polar or polar molecules. In repeated measurements, we bring our “oil” close to the surface of sand grains removed from core plugs, which represent the pore walls in sandstone and we measure the work of adhesion between the tip and surface. Adhesion work is proportional to wettability and is directly correlated with the salinity of the fluid in contact with the tip and the particle surface. The threshold values for the onset of the low salinity response (5000 to 8000 ppm) benchmark remarkably well with those observed from core plug tests. Changing either the type of “oil” on our probe or the substrate both affect the adhesion response. From a mechanistic perspective, the correlation between salinity and adhesion provides evidence for the role of electrical double layer expansion in the salinity water flooding; expansion of the double layer decreases oil wettability
Since the first introduction of Smart Waterflooding in carbonates rocks by Saudi Aramco in 2010 (Yousef et al., 2010), tuning the salinity and ionic composition of injecting water in carbonate reservoir has been considered as one of the most promising economical IOR/EOR method. Thanks to the numerous efforts in this field of researches for last a few decades, it is quite clear rock wettability alteration is one of the key mechanisms for increasing oil recovery. So far, most studies related to low salinity effects and Smart Waterflooding focused on the physical and chemical pore system alterations with multi-phase fluid system, which includes water and oil in either sandstone or carbonates. Without, however, fundamental understanding of single-phase fluid (water) - rock interaction, there will always be unanswered questions lying behind the study related to the IOR/EOR by controlling water chemistry.
The current study is focused on individual key ions (Ca2+, Mg2+, (SO4)2-) effects on carbonate rock by only injecting water with controlled amount of separate or combined key ions into the selected carbonate rock. A recently proposed MR-CT microscopy (Kwak et al., 2012) has been a tool of choice for the current research work since it can monitor the physical and chemical alteration of rock surface after interacting with fluids with specific types and amount of ions. In addition, since MR-CT microscopy is non-destructive measurement, the effect of various types of fluids with the identical rock sample before, during, and after core flooding test repeatedly.
NMR results indicate that the magnitude of water-rock interaction changes when injecting different types of ions. These results provide more insight on how key ions interact with carbonate rock surface. In addition, the different reactivities of rock surfaces with different mineralogy have been monitored when specific types of ions are injected. The fundamental understanding acquired by the current study, effects of key ions in carbonate rock with single-phase fluid will be a very important stepping stone to build rigid understanding of more complicated multi-phase fluid interaction with various types of reservoir rocks, and eventually draw conclusions on how these ions change rock wettability.
Miscibility with oil lies among the main advantages of dense CO2 injection for pore scale oil displacement during tertiary recovery. At reservoir scale, injecting dense CO2 in the form of foam can also improve its sweep efficiency. However, although the use of such miscible dense CO2 foams has been considered in over twenty pilots since the 1980’s, only few lab studies have considered foams formed with CO2 in this particular thermodynamical state. Indeed, dense CO2 has solvation properties and a viscosity higher than that of a gas. Although the generic term of foam is used, dense CO2 actually has liquid-like properties, and dense CO2 foams should be coined emulsions. This impacts several attributes of these dispersions in porous media, such as Mobility Reduction Factors (MRF) and behavior in presence of oil.
We present new results demonstrating that classical foamers are not effective in improving mobility control of dense CO2 in porous media. However, relatively high MRF can be achieved using carefully formulated surfactants. Based on these findings, we study the impact of foam on miscible flooding efficiency in coreflood experiments. Reversely, we also evaluate how miscibility of CO2 with oil impacts foam MRF. Our approach is based on multiple corefloods experiments, with different formulations, at various oil saturations. Additionally, physical-chemistry measurements such as interfacial tension estimations and foam stability monitoring are performed in reservoir conditions (pressure and temperature). This set of experiments shows that besides ability to reduce dense CO2 mobility in porous media, a balance must be found between maximizing MRF and minimizing the risk of emulsion formation in porous media.
This paper brings new insights on the interpretation of CO2 foams coreflood results, based on the thermodynamical properties (solvation power, density, viscosity) of the CO2 phase. In particular, it provides the reader with a clearer view of gas properties that must be considered when analyzing results of dense CO2 foams corefloods. This can help reconcile seemingly contradictory results appearing in the literature, particularly regarding the values of MRF obtained with CO2 foams as a function of pressure and in the presence of oil.
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.
Performance prediction of reactive processes such as those associated with injection of chemicals that react with rock and fluids require accurate models of the processes. Frequently, these processes are studied at laboratory scale and modeling them at the field scale entails scale-up of laboratory observations taking into account the variability of parameters. Current practice of scale-up is to perform spatial averaging of attributes and account for residual variability by calibration and history matching. This results in poor predictions of future reservoir performance. In this paper we scale-up these reactive transport processes considering both the spatial and temporal characteristics of these processes.
The first part of the paper investigates spatiotemporal scale-up of dispersivity with field heterogeneity and reactivity of CO2 injection through numerical simulations. Transport processes in reservoir models at three different length scales are simulated using homogeneous and heterogeneous permeability models. The variation in dispersivity with spatiotemporal scale is plotted and various conclusions are deduced regarding the impact of the permeability and conservative/reactive transport. In the second part of the paper, a semi-analytical model for spatiotemporal covariance describing the reaction-dispersion process is used to derive the Representative Elementary Volume (REV) of concentration in combined space and time. This spatiotemporal covariance is used to compute the variance of mean concentration. The stabilization of this variance is indicative of the REV.
Key results of this work indicate that scaling characteristics of dispersivity distinctly differ for low permeability and high permeability media. Heterogeneous media exhibit scaling characteristics for both high and low permeability media. Another important result is that reactions affect scaling characteristics of dispersivity at only small and intermediate scales. The semi-analytical models for scale-up of reaction-dispersion processes indicate that purely spatial or temporal investigation does not produce accurate estimate of REV. However, when scaling is investigated in a spatiotemporal setting, then the REV can be defined fairly accurately.
These results can be important for designing laboratory experiments and to predict scaled-up field response. Additionally, results also demonstrate that spatiotemporal numerical discretization of recovery processes should be done appropriately after finding the combined spatiotemporal REV scale of the process.