bluuebunny/crossref_metadata_2025_split huggingface dataset:
Emulsion Flooding of Heavy Oil
Authors: Kumar R. , Dao E. , Mohanty K. K. 
Published: July 2010

Abstract
The goal of this work is to develop alkaline-surfactant methods to improve recovery from a heavy oil reservoir in the north slope of Alaska. Phase behavior experiments were conducted to determine conditions under which oil-in-water emulsions form. The viscosity (and its shear dependence) was measured for some of these emulsions. Reservoir sand was assembled in sand packs. Water flood and alkaline-surfactant floods were conducted at several salinities. Several relatively hydrophilic surfactants were identified which formed oil-in-water emulsions with the reservoir oil at a low concentration in the presence of sodium carbonate. Emulsions formed at low salinity and high oil-water-ratio. Viscosity of these emulsions was relatively low compared to the oil viscosity. Waterflood recovery was of the order of 20-30% PV and it decreased as the injection rate increased. The alkaline-surfactant flood following the waterflood gave an incremental oil recovery of 20-40 % PV. Alkaline-surfactant floods look promising, but the mechanisms of this flood need to be understood to upscale this process to the field.
Nanoparticle-Stabilized Supercritical CO2 Foams for Potential Mobility Control Applications
Authors: Espinosa David , Caldelas Federico , Johnston Keith , Bryant Steven L. , Huh Chun 
Published: July 2010

Abstract
Surfactant-stabilized CO2 foams have been used for mobility control for CO2 flooding; however, stabilization of foams with nanoparticles has some important advantages for EOR applications. Bringing the nanoparticles to the bubble interface requires a large adsorption energy, making the resulting foam very stable. Nanoparticles being solid, the nanoparticle-stabilized foams have potential to withstand the high-temperature reservoir conditions for extended periods. With their very small size, nanoparticles (and foam bubbles stabilized by them) can be transported without straining in pore throats in the reservoir rock.
Very stable supercritical CO2-in-water foams were generated with 5-nm silica nanoparticles whose surface was treated with short-chain polyethylene-glycol. The foams were generated by co-injecting CO2 and an aqueous dispersion of the nanoparticles through a glass-beads pack, at mixture flow rates that correspond to shear rates of ~1300 s-1. The domain of foam stability and the normalized mixture viscosity have been measured for a range of values of nanoparticle concentration, water salinity, ratio of CO2/water flow rates, the overall flow rate and temperature. With deionized water, stable foams formed at nanoparticle concentrations as low as 0.05 wt%. Larger particle concentrations were required to maintain foam stability at larger salinities, e.g., 0.5 wt% particle concentration for 4% NaCl brine. Foam stability was independent of CO2/water volume ratio for ratios between two and eleven, but the normalized mixture viscosity increased with the increase in ratio. When foam was generated, it had two to eighteen times more resistance to flow than the same fluids without nanoparticles. Foams were generated at temperatures up to 95 °C. Foam generation by co-injection of the fluids appears to require a threshold shear rate.
A Designer Water Process for Offshore Low Salinity and Polymer Flooding Applications
Authors: Ayirala Subhash , Uehara-Nagamine Ernesto , Matzakos Andreas , Chin Robert , Doe Peter , van Den Hoek Paul 
Published: July 2010

Abstract
Low salinity water flooding is getting much wider attention in the oil industry since it is highly cost-competitive compared to other conventional EOR methods. Water desalination and hardness removal are the keys to its success for effective oil recovery. However, conventional seawater desalination methods provide almost fresh waters that could be incompatible with resident reservoir clays and hence may not be suitable for direct injection into the reservoir. In this paper, we describe a novel "designer water" desalination scheme that is capable of providing the desired injection water composition to suit the specific formation. Thus, this process could potentially avoid clay-swelling, and at the same time mitigating other critical issues such as reservoir souring and unfavourable wettability modification to more oil-wet state. Selected examples are given to conceptually demonstrate how various water streams generated in the designer water process would help to move the injection water quality point away from the clay flocculation region for different reservoir clay types.
Polymer flooding is another promising avenue for low salinity water applications. The use of low salinity water in polymer flooding processes considerably reduces the amount of dosing chemicals required to achieve a target polymer solution viscosity. This favourably impacts chemical procurement, transportation, storage, and handling (mixing and hydration) requirements and operating costs in offshore environments. The effect of injection water salinity on polymer concentration requirements is shown for different polymer solution viscosities. These data indicate about 5-10 times lower consumption of polymer in low salinity water when compared to seawater. As a result, a high-level facility engineering study was performed to assess the cost savings associated with low salinity water in offshore polymer flooding. The study results show that polymer flooding with low salinity water is economically more beneficial compared to seawater polymer flooding. It could be possible to pay out the incremental desalination costs within a 4-year project time frame due to the large savings associated with chemical costs and polymer facilities costs in low salinity polymer flooding. When the reservoir fits the criteria for low salinity flooding, then the additive effect of lower waterflood remaining oil saturation compounds with the benefit of polymer flood improved oil recovery due to better reservoir sweep. This means that low salinity water flooding can synergize well with polymer flooding to drive unit technical cost down and oil recoveries up.
Propagation of Colloidal Dispersion Gels (CDG) in Laboratory Corefloods
Authors: Spildo K. , Skauge A. , Skauge T. 
Published: July 2010

AbstractLaboratory core floods have demonstrated increased oil recovery by injection of colloidal dispersion gels (CDG). CDG consist of roughly spherical particles with sizes in the nanometre range (50-150 nm), formed by a crosslinking reaction between aluminium and partially hydrolysed polyacrylamide (HPAM). Investigations have shown that the physio-chemical properties of CDG solutions are similar to aqueous solutions of colloids. Such solutions may contribute to EOR by giving both microscopic diversion of flow and macroscopic sweep improvement.Questions have been raised as to whether CDGs can propagate a substantial distance into porous rock and thus contribute to oil mobilization. To our knowledge, this matter has previously not been subject to experimental verification. The present study reports several experiments dedicated to investigate this matter.CDG retention in porous media can be due to adsorption, mechanical entrapemnt and/or a log-jamming mechanism. More extended polymer molecules can also be retained by mechanical trapping in the presence of sufficiently small pore throats. We have studied the retention of polymer and aluminium in Berea cores, both separately and as part of a CDG formulation. The results show no chromatographic separation between aluminium and polymer in the CDG injection experiments. The core floods have also shown a constant equilibrium ratio between aluminium and polymer being produced. Earlier laboratory results have also shown no change in particle size distributions of the CDG formulation in the effluent after an oil mobilization experiment.
Nano-Sized Particles for EOR
Authors: Skauge Tormod , Hetland Sverre , Spildo Kristine , Skauge Arne 
Published: July 2010

Abstract
During the last decades colloidal dispersion gels (CDG) have been applied as an EOR method, providing sweep improvement in reservoirs with unfavourable mobility ratio. Our core flood results also indicate an improved microscopic sweep or microscopic diversion by CDG. This paper investigates the oil mobilization properties of nano-sized silica particles in comparison to nano-sized CDG particles and discusses the underlying mechanisms of microscopic flow diversion.
Improved microscopic displacement efficiency has traditionally been coupled to changes in capillary number. However, this approach is insufficient to describe processes like low salinity injection, colloid dispersion gels, and microbial enhanced oil recovery.
This paper presents a new concept of EOR by improved microscopic displacement defined as microscopic diversion. This method involves pore blocking and diversion of injection fluids. Multi-phase flow experiments using nano-sized silica particles attempts to investigate the effect (inelastic) nano-sized fines migration can have on oil mobilization by microscopic diversion.
The oil mobilization properties were investigated by core floods using well-defined nano-sized silica particles in comparison with injection of CDG, polymer or silica particles dispersed in a polymer solution. Core floods were performed on water-wet Berea sandstone cores with permeabilities of approx. 500 mD. The comparison of inelastic silica particles, polymer solutions and nano-sized CDG particles allowed an evaluation of the importance of viscoelastic properties for microscopic diversion.
Water Shut-off Polymer Systems: Design and Efficiency Evaluation based on Experimental Studies
Authors: Vega I. , Morris W. , Robles J. , Peacock H. , Marín A. 
Published: July 2010

Abstract
Water production control is a key issue in most mature reservoirs worldwide. Many techniques have been developed to achieve this purpose. Water Shut-off (WSO) treatments using crosslinked gels have proven to be an effective alternative. When appropriately designed and applied, these systems generate flow restrictions in high permeable or fractured formations that bypass water from highly saturated zones (injection water or natural brines). WSO treatments efficiency depends on several aspects as reservoir fluids flow patterns, rock petrophysics, formation heterogeneity, and WSO gel characteristics. This last aspect is adjusted to optimize the treatment based on experimental tests performed in the laboratory.
This paper presents an experimental methodology to evaluate and adjust WSO polymer systems according to operational and treatment performance requirements. These studies go from qualitative gel consistency and fluid compatibility bottle tests, to rheological characterizations to determine viscosity variations and gelation time (outside porous media tests), as well as flow tests performed on formation and Berea core plugs at reservoir conditions (inside porous media tests).
These properties are highly important to avoid early gelations and, at the same time, assure the appropriate WSO placement in the reservoir. Viscoelastic properties such as G* (complex modulus), G′ (storage modulus) and G″ (loss modulus) define the gel strength and provide structural information such as crosslinking density. These parameters are essential to design the gel formulations (polymer and crosslinker type and concentration) depending on the operational and reservoir requirements.
Finally, the flow tests performed on core plugs show the changes in water and oil permeability after injecting the treatment. This information is used to calculate the residual resistance factors to water (RRFw), oil (RRFo) and the gel resistance index (GRI). These parameters define the treatment blockage degree and allow estimate probable well production response as well as the best production regimes to extend the treatment life time. This methodology was applied on a new WSO gel system, developed for a wide range of applications. The effect of polymer concentration, temperature, salinity and flow rate are examined in detail.
Experimental tests are many times underestimated when planning a WSO job; however these tests will always provide valuable information that will increase the chances of successful water shut-off treatments. The connection between laboratory and field parameters and its influence in the oil and water productivity were analyzed.
New Gel Aggregates for Water Shut-off Treatments
Authors: Lei Guanglun , Li Lingling , Nasr-El-Din Hisham A. 
Published: July 2010

Abstract
A common problem for oil production is the excessive water production, which can lead to rapid productivity decline, and enhancement in operating costs. The result is often a premature shut-in of wells because production has become uneconomical. In water injecting wells, the water injection profiles are uneven and large amounts of oil have been left behind the waterfronts.
Many chemical systems have been used to control water and improve recovery from reservoirs with high water-cut. Non-polymer or inorganic gels have low viscosity and can be pumped using typical field mixing and injection equipment. Polymer or cross-linked gel, especially polyacrylamide, based techniques are largely used because of their relatively low cost and their supposed selectivity.
In this paper, microspheres (5-30 microns) were synthesized using acrylamide monomers cross-linked with an organic cross-linker. They can be suspended in water and be pumped in sandstone formations. They can plug some of the pore throats, thus force water to change its direction and increase the sweep efficiency. A HPHT rheometer was used to measure G' (elastic modulus) and G" (viscous modulus) of these aggregates.
Experimental results indicate that these microspheres are stable in solution with 20,000 ppm NaCl, at 175°F. They can expand up to 5 times of their original size in water and show good elasticity. The results of sand pack tests show that the microspheres can flow into cores with more than 500 md and can increase the resistance factor by 8~25 times and the residual resistance factor by 9 times. Addition of microspheres to polymer solutions further increased the resistance factor beyond that obtained with polymer solution. Field data using microspheres showed improvement the in the injection water profile.
Two-Phase and Three-Phase Saturation Routes and Relative Permeability During Fast Drainage
Authors: Dehghanpour H. , DiCarlo D. A. , Aminzadeh B. , Mirzaei M. 
Published: July 2010

Abstract
We conduct two- and three-phase drainage experiments in a 0.8 meter water wet sand column with varying initial conditions. We measure saturations versus space and time using a dual energy CT-scanner technique. A non-linear interpolation technique is used to synchronize measured CT profiles. The relative permeabilities are determined using the fluxes obtained from the measured saturation profiles and assuming flow under unit gravitational gradient.
At times greater than 15 minutes, the gradient of oil and water saturation data is relatively small far from the air front, allowing accurate determination of relative permeabilities. We observe a pronounced difference in the drainage behavior of the systems with and without initial trapped air. For early times and high saturations (S&gt;0.3), we obtain relative permeabilities and they follow the previously measured trend at low saturations. We compare two- and three-phase relative permeabilities of oil and water. We explain the optimum initial condition for relative permeability measurement during gravity drainage, and we discuss the situations where this method fails to determine representative relative permeability data.
Application of the Multiwell Productivity Index-Based Method to Evaluate Interwell Connectivity
Authors: Kaviani D. , Valkó P. P. , Jensen J. L. 
Published: July 2010

Abstract
Numerous studies have concluded that connectivity is one of the most important factors controlling success of improved oil recovery processes. Interwell connectivity evaluation can help identify flow barriers and conduits and provide tools for reservoir management and production optimization. The multiwell productivity index (MPI)-based method provides the connectivity indices between well pairs based on injection/production data. By decoupling the effects of well locations, skin factors, injection rates, and the producers’ bottomhole pressures from the calculated connectivity, the heterogeneity matrix obtained by this method solely represents the heterogeneity and possible anisotropy of the formation. Previously, the MPI method was developed for bounded reservoirs with limited numbers of wells. In this paper, we extend the MPI method to deal with cases of large numbers of wells and open reservoirs.
To handle open reservoirs, we applied some modifications to the MPI method by adding a virtual well to the system and by modifying the pore volume. We applied the modifications in two nonvolumetric systems where there was either a leaking zone or an isolated zone, and found the approaches using the virtual well could predict the reservoir performance accurately. In cases with large numbers of wells, the required computational time to calculate the heterogeneity matrix may make the problem intractable. Therefore, we applied a model reduction strategy based on the location of the wells, called windowing. This technique ignores the parameters that have smaller effects on reservoir performance. We applied windowing to two cases with large numbers of wells (16 and 41 wells). We observed that, by selecting the proper window size, we can predict the reservoir performance accurately (R2 values greater than 99%) and decrease the CPU time up to a factor of 20 for the studied cases.
The approaches described enabled us to provide realistic interpretations of interwell connectivity for complex cases where the simple MPI method would be difficult to apply. Integration of these approaches with the MPI method can quickly and efficiently model field data to optimize well patterns and flood parameters.
Simultaneous Water-Gas-Injection Performance Under Loss of Miscibility
Authors: Ghanbarnezhad Rouzbeh , Lake Larry W. 
Published: July 2010

Abstract
This paper concerns the limits of the Walsh and Lake (WL) method for predicting solvent-flood performance when miscibility is not achieved. Despite extensive research on applications of fractional flow theory, prediction of flow under loss of miscibility has not been investigated thoroughly.
We introduce the idea of an analogous first-contact miscible (FCM) flood to the WL method. To compare the WL solution of degraded miscible simultaneous water and gas (SWAG) displacements, we use numerical simulations. In the simulations, the loss of miscibility is attributed to either dispersion or insufficient pressure (degradation).
The results of one-dimensional (1D) SWAG injection suggest that results of the WL method and the simulations are in agreement when the input dispersion is limited. For the two-dimensional (2D) displacements, the WL predicted optimal water- alternating-gas (WAG) ratio is accurate in two sets of simulation cases: (1) fairly homogeneous permeable media with limited cross flow (2) heterogeneous permeable media with lateral correlation length of the same size or larger than the interwell spacing. The accuracy of the WL method improves in the latter cases as the cross flow decreases. Also, we observe a linear growth of the mixing zone with time in cases where the WL solution and the numerical results are consistent. Further investigation illustrates an inverse relation between the level of mixing, resulting from the input dispersion and heterogeneity, and the accuracy of the WL approach. Through this work, the effect of dispersion and miscibility degradation on the miscible residual oil saturation, Sorm, is determined.
Results of a Three-Well Waterflood Sweep Improvement Trial in the Prudhoe Bay Field Using a Thermally Activated Particle System
Authors: Husband Michael , Ohms Danielle , Frampton Harry , Carhart Steve , Carlson Brian , Morgan Jim C. , Chang K. T. 
Published: July 2010

Abstract
Maintaining proper waterflood conformance is a critical component of waterflood management. Most methods used to control waterflood conformance have proven to be only marginally effective. A unique technique has been developed for creating a durable reservoir flow restriction that diverts injected water into unswept reservoir sections. Placement of the restriction is based in the location of the thermal front between the injector and producers. The performance of this thermally activated particulate system for waterflood conformance control has been evaluated in a three injection well trial in the Prudhoe Bay oilfield, Alaska. The aim of the trial was to determine the incremental oil produced and improvement of sweep efficiencies for three interior water injection patterns in the east waterflood area of Greater Prudhoe Bay Unit.
Wettability Challenges in Carbonate Reservoirs
Authors: Alotaibi M. B. , Nasralla R. A. , Nasr-El-Din H. A. 
Published: July 2010

Abstract
Injection of water for pressure maintenance and waterflooding applications is becoming an increasingly important issue. Historically, the total suspended solids of the water were given more consideration rather than the total dissolved solids. The water from injection wells physically sweeps the displaced oil to adjacent production wells. Displacement of the oil is highly affected by many interacting variables. Wettability has been recognized as one of the controlling parameters of the remaining oil-in-place. Brine salinity, oil chemistry, and rock lithology are believed to play a significant role on altering rock wettability. Recent studies highlted that low salinity water can increase oil recovery in carbonate reservoirs.
This paper highlights extensive wettability studies to determine the optimum brine salinity, which results in higher oil recovery. Contact angle and Amott imbibition methods are considered as the most common methods to measure the preferential affinity of reservoir rocks. Crude oil, formation core samples (dolomite, and calcite), and synthetic brines from Middle East (formation, aquifer, and seawater) are used to evaluate wettability quantitatively, and qualitatively. All experiments were conducted at high pressure (up to 2,000 psia), and elevated temperature (up to 270°F).
Contact angle decreased with pressure, and temperature upto 194°F. The optimum salinity is found that can enhance the rock wettability toward water-wet. Currently, there is confusion concerning the optimum brine salinity for injection wells. The results of this study give a new insight on the optimum salinity and provide better understanding of some wettability challenges in carbonate reservoirs.
Investigation of Pore-Scale Mixed Wettability
Authors: Kumar Munish , Fogden Andrew , Senden Tim , Knackstedt Mark 
Published: July 2010

Abstract
The efficiency of secondary and tertiary recovery processes can be improved by properly taking into account the reservoir's true wettability state. Most reservoirs are assumed to be mixed-wet, based on core-scale indexes such as Amott-Harvey and USBM. Oil-brine-mineral contact angle measurements on smooth substrates offer some molecular-scale input and estimates for network modelling. However, direct experimental techniques to characterize wettability and validate the mixed-wet model at the pore scale in real or model rocks remain elusive. One promising avenue is the use of micro-tomography (μ-CT) to map the pore-scale distribution of multiple phases in miniplugs. A second, complementary approach involves the study of model rocks based on bead packs to probe the surface chemistry of the minerals exposed to crude oil and brine in pore confinement. Integrating the two approaches described in the current study provides a promising means to explain the observed multiphase fluid occupancy in pores by combining the detailed knowledge of the 3D pore structure and information on the surface chemistry of its walls.