bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rheology of Supercritical CO2 Foam Stabilized by Nanoparticles
Authors: Xiao Chongwei , Balasubramanian Suriya N. , Clapp Lee W. 
Published: March 2016

Abstract
Foamed fluids with the gas phase of carbon dioxide (CO2) have been applied as fracturing fluids to develop unconventional resources. This type of fracturing fluids meets the waterless requirements by unconventional reservoirs, which are prone to damage by clay swelling and blocking pore throat in water environment. Conventional CO2 foams with surfactants have low durability under high temperature and high salinity, which limit their application. Nanoparticles provide a new technique to stabilize CO2 foams under harsh reservoir conditions. It's essential to determine in-situ rheology of CO2 foams stabilized by nanoparticles in order to predict proppant transport in reservoir fractures and improve oil production.
The shear viscosity and foam texture of non-Newtonian fluids under reservoir conditions are critical to transport proppant and generate effective micro-channels. This study determined the in-situ shear viscosity of supercritical CO2 foams stabilized by nano-SiO2 in the Flow Loop apparatus with shear rates of 5950~17850 s−1 at the pressure of 1140±20 psig and the temperature of 40 °C. Supercritical CO2 with the density of 0.2~0.4 g/ml and the viscosity of 0.02~0.04 cp under typical reservoir conditions were applied to generate foams. The foams were tested with high foam quality up to 80% to minimize the usage of water. The effects of shear rates, salinity, surfactant, and nanoparticle sizes and on the rheology of gas foams with different foam qualities were experimentally investigated. The foam texture and stability were observed through an in-line sapphire tube. Further, proppant transport by CO2 foams and the placement in fractures were analyzed by considering the rheology of non-Newtonian fluids and the mechanisms of gravity driven settling and hindered settling/slurry flow.
The conditions of nanoparticle foaming systems were optimized through orthogonal experimental design. The dense and stable foams were generated and observed under high pressure and elevated temperature conditions. It was observed that CO2 foams with high quality of 80% demonstrated the highest viscosity and stability under optimal conditions. The foams with nanoparticles demonstrated both shear- thinning and shear-thickening behaviors depending on foam quality and components. The salinity and nanoparticle size affect foam rheology in two ways depending on components, foam quality, and shear rates.
While the viscosities of CO2 foam stabilized by nanoparticles have been widely studied recently, no work has been done to observe the stability and texture of supercritical CO2 foam after shearing under high pressure and high temperature, not to mention proppant transport by CO2 foam. This study provided a pioneering insight to the proppant transport by viscous supercritical CO2 foam stabilized by nanoparticles.
Low Salinity Waterflooding: From Single Well Chemical Tracer Test Interpretation to Sector Model Forecast Scenarios
Authors: Spagnuolo Marco , Callegaro Chiara , Masserano Franco , Nobili Marianna , Sabatino Riccardo , Blunt Martin J. 
Published: March 2016

Abstract
We study Enhanced Oil Recovery (EOR) through Low Salinity (LS) waterflooding in a brown oil field. LS waterflooding is an emerging EOR technique in which water with reduced salinity is injected into a reservoir to improve oil recovery, as compared with conventional waterflooding, in which High Salinity (HS) brine or seawater are commonly used. The efficiency of this technique can be quantified at the well-scale by a Single Well Chemical Tracer Test (SWCTT), which is an in-situ method for measuring the Remaining Oil Saturation (ROS) after flooding the near-wellbore region with a displacing agent. Two SWCTTs were executed on a sandstone North African field. The tests were realized in sequence with seawater and LS water to evaluate the EOR potential at the well-scale.
Here, we propose the interpretation of these two SWCTTs. They were modeled through numerical simulations because of the presence of several non-idealities in the complex scenario considered. A recently-developed tracer simulator was employed to solve the reactive transport problem. This was used as a fast post-processing tool coupled with a conventional reservoir simulator. Model parameters were estimated within an inverse modeling framework, on the basis of an assisted history matching procedure that exploits the Metropolis Hastings Algorithm (MHA). Results were scaled up on a sector model of the field, and forecast scenarios that consider a field-scale implementation of this technique were defined.
The well-scale displacement efficiency gain associated with LS water, as compared with seawater, was evaluated. It was quantified as a ROS reduction of 8 saturation unit (s.u.), with a P10–P90 range of 3–15 s.u. Reservoir-scale simulations suggest that the associated ultimate oil recovery of the EOR pilot may be increased by 2% with LS water, with a P10–P90 range of 0.7–4.3%.
Overall, the LS EOR potential for a selected field was quantified through a robust and original workflow, based on SWCTT interpretation. This state-of-the-art procedure is now available for further applications. The simulated oil recovery improvement with LS water is promising, and leads the way to the implementation of an inter-well field trial.
Microemulsion Formation and its Effects on in Situ Rheology During ASP Corefloods: Scouting Study
Authors: Unsal Evren , Oedai Sjaam , van Wunnik John 
Published: March 2016

Abstract
During an Alkaline-Surfactant-Polymer (ASP) flood in reservoir rock, often an in situ microemulsion phase forms upon contact of the injected ASP fluid with the residing oil. These microemulsions form as a result of the required ultra-low interfacial tensions (IFT) for oil mobilization and displacement of the residual oil, but they can have a high viscosity. The success of an ASP flood on oil recovery depends on the complex flow of the injected ASP solution, the mobilized oil and the in situ microemulsion phase, which the latter often has a higher shear-dependent viscosity than the other two.
In this study, steady-state (SS) corefloods have been performed to investigate the in situ microemulsion formation and rheology during the multiphase flow. The aqueous phase, namely brine, AS or ASP, was co-injected with n-decane or reservoir ‘dead’ crude in Berea outcrop cores for a range of fractional flow ratios. The pressure differential was continuously recorded, and was then converted in an apparent, in situ, viscosity value. For this stage of the project the water and oil phase saturations in the plugs were not yet measured.
For brine/oil systems some dependence of apparent viscosity on rock permeability was observed; for systems with surfactants no such trend was noticable. The addition of surfactants substantially reduced the apparent viscosities; the viscosity reducing impact of surfactants could be balanced by the addition of polymer. Fractional flow analysis showed that the addition of surfactants reduces the impact of capillary forces resulting in straightened relative permeability curves and higher aqueous phase relative permeability end points.
It is anticipated that this study leads to a fast and fit for purpose characterization method of ASP-crude oil systems that provides data in a form, such as relative permeability data and residual oil saturation that can be applied directly in reservoir simulators.
Tradeoffs Between Emulsion and Powder Polymers for EOR
Authors: Jouenne S. , Klimenko A. , Levitt D. 
Published: March 2016

Abstract
Polymer transport and preparation can present a key challenge in chemical EOR project implementation.
Hydrolyzed polyacrylamide in emulsion form presents some advantages, including an easier transportation and a simplification of the injection process. The trade off is a lower active concentration (~30% - 50%), which increases the volumes to be transported, as well as the presence of oil and emulsifiers, which may have unintended effects in the reservoir.
In this article, we compare two industrial and commercially-available polymers, one in powder form from the gel process, and the other in an inverse emulsion, with similar viscosifying power.
Properties of both polymers are investigated through rheological and screen factor measurements, filterability tests on bulk solutions, shear thickening behavior and resistance to shear degradation in porous medium. The likely origin of the observed differences is discussed in light of the two polymerization methods (bulk vs. emulsion) that lead to differences in polydispersity. Mobility reduction and residual resistance factor measurements during propagation tests at low velocity give some insight on the propagation of the stabilized oil droplets coming from the injected emulsion. Finally, oil recovery efficiency is investigated through secondary polymer injections on sandpacks. No significant difference was observed between the polymers in term of oil recovery or pressure behavior.
These results are relevant to oil companies planning polymer or surfactant-polymer pilots and considering the tradeoffs between emulsion and powder polymers.
CO2 Foam Pilot in Salt Creek Field, Natrona County, WY: Phase III: Analysis of Pilot Performance
Authors: Mukherjee Joydeep , Nguyen Quoc P. , Scherlin John , Vanderwal Paul , Rozowski Peter 
Published: March 2016

Abstract
A supercritical CO2 foam pilot, comprised of a central injection well in an inverted 5-spot pattern, was implemented in September 2013 in Salt Creek field, Natrona County WY. In this paper we present a thorough analysis of the pilot performance data that has been collected to date from the field. A monitoring plan was developed to analyze the performance of the pilot area wells before and after the start of the foam pilot. The injection well tubing head pressure was controlled to maintain a constant bottom hole pressure and the fluid injection rates were monitored to capture the effect of foam generation on injectivity. Inter-well tracer studies were performed to analyze the change in CO2 flow patterns in the reservoir. Production response was monitored by performing frequent well tests. The CO2 injection rate profile monitored over several WAG cycles during the course of the implementation clearly indicates the formation and propagation of foam deep into the reservoir. CO2 soluble tracer studies performed before and after the start of the foam pilot indicate significant areal diversion of CO2. The production characteristics of the four producing wells in the pilot area indicate significant mobilization of reservoir fluids attributable to CO2 diversion in the pattern. The produced gas-liquid ratio has decreased in all four of the producing wells in the pattern. Analysis of the oil production rates shows a favorable slope change with respect to pore volumes of CO2 injected. Segregation of CO2 and water close to the injection well seems to be the primary factor adversely affecting CO2 sweep efficiency in the pilot area. Foam generation leads to a gradual expansion of the gas override zone. The gradual expansion of the gas override zone seems to be the principal mechanism behind the production responses observed from the pilot area wells.
Permeability Reduction Due to use of Liquid Polymers and Development of Remediation Options
Authors: Dwarakanath Varadarajan , Dean Robert M. , Slaughter Will , Alexis Dennis , Espinosa David , Kim Do Hoon , Lee Vincent , Malik Taimur , Winslow Greg , Jackson Adam C. , Thach Sophany 
Published: March 2016

Abstract
Polymer flooding by liquid polymers is an attractive technology for rapid deployment in remote locations. Liquid polymers are typically oil external emulsions with included surfactant inversion packages to allow for rapid polymer hydration. During polymer injection, a small amount of oil is typically co-injected with the polymer. The accumulation of the emulsion oil near the wellbore during continuous polymer injection will reduce near wellbore permeability. The objective of this paper is to evaluate the long-term effect of liquid polymer use on polymer injectivity. We also present a method to remediate the near well damage induced by the emulsion oil using a remediation surfactant that selectively solubilizes and removes the near wellbore oil accumulation. We evaluated several liquid polymers using a combination of rheology measurement, filtration ratio testing and long-term injection coreflood experiments. The change in polymer injectivity was quantified in surrogate core after multiple pore volumes of liquid polymer injection. Promising polymers were further evaluated in both clean and oil-saturated cores. In addition, phase behavior experiments and corefloods were conducted to develop a surfactant solution to remediate the damage induced by oil accumulation. Permeability reduction due to long term liquid polymer injection was quantified in cores with varying permeabilities. The critical permeability where no damage was observed was identified for promising liquid polymers. A surfactant formulation tailored for one of the liquid polymers improved injectivity three- to five-fold and confirms our hypothesis of permeability reduction due to emulsion oil accumulation. Such information can be used to better select appropriate polymers for EOR in areas where powder polymer use may not be feasible.
Modeling Dynamic Wettability Alteration Effect Based on Contact Angle
Authors: Lashgari Hamid R. , Xu Yifei , Sepehrnoori Kamy 
Published: March 2016

Abstract
This paper presents a dynamic wettability alteration model based on the Gibbs adsorption isotherm equation. The model is conceptually and thermodynamically developed for ideal surfactant solutions (i.e anionic surfactants) that reduce the surface tension between oil phase and rock formation based on the contact angle in a preferentially oil-wet formation. We assume that interfacial tension (IFT) between oil/water and oil/gas remain unchanged in the presence of surfactants. In order to apply the effect of contact angle on multiphase fluid flow in porous media, existing relative permeability and capillary pressure models are modified to become a function of contact angle to mimic the influence of wettability alteration.
The developed models can be tuned with experimental data including the contact angle, relative permeability, and capillary pressure parameters then they can be used to predict the efficiency of surfactant injection processes in naturally fractured reservoirs accordingly.
Viscosity and Stability of Dry CO2 Foams for Improved Oil Recovery
Authors: Da Chang , Xue Zheng , Worthen Andrew J. , Qajar Ali , Huh Chun , Prodanovic Maša , Johnston Keith P. 
Published: March 2016

Abstract
CO2/water foams are of interest for mobility control in CO2 EOR and as energized fracture fluids, or hybrid processes that combine aspects of both processes. In fracturing applications, it would be desirable to lower the water level as much as possible to minimize the production of wastewater and formation damage. It is challenging to stabilize ultra dry foams with extremely high internal phase gas fraction given the high capillary pressure and the rapid drainage rate of the lamellae between the gas bubbles. However, we demonstrate that these ultra dry CO2-in-water foams may be stabilized with surfactants that form viscoelastic wormlike micelles in the aqueous phase. These wormlike micelles are formed by tuning the surfactant packing parameter with electrolytes or a second oppositely-charged surfactant to stabilize ultradry CO2-in-water foams with foam qualities as high as 0.98 and apparent viscosities more than 100 cP up to 90 °C. Applicability of these foams for improved oil recovery is evaluated by running multiphase flow injection simulations in a case-study oil reservoir.
Improving Recovery of a Viscous Oil Using Optimized Emulsion Viscosity
Authors: Aminzadeh Behdad , Hoang Viet , Inouye Art , Izgec Omer , Walker Dustin , Chung Doo , Nizamidin Nabijan , Tang Tom , Lolley Chris , Dwarakanath Varadarajan 
Published: March 2016

Abstract
Alkali flooding in heavy oil reservoirs is known to stabilize emulsion in-situ and improve the recovery beyond that of conventional waterflood under certain boundary and initial conditions. The overarching goal of this study is to develop a systematic approach to optimize this process and capture underlying recovery mechanisms. Therefore, we experimentally evaluated the performance of alkali flood as a function of emulsion type and viscosity. Phase behavior and viscosity of the microemulsion are modified by introducing seven different surfactants. Microscope imaging techniques are employed to measure the droplet size distribution for type I and II emulsions. Viscosities of generated emulsions are measured with a rotational rheometer at low temperatures and with an electromagnetic viscometer at reservoir conditions. Finally, corefloods are conducted at different conditions to evaluate the performance of displacement as a function of emulsion type and viscosity. Enhanced alkali floods showed an incremental recovery of 8 – 50% beyond that of waterflood. Formation of higher viscosity emulsion has a large contribution on the sweep efficiency and therefore improved oil recovery during alkali flood; however, other mechanisms (e.g. entrainment and entrapment) also have contribute to the incremental recovery. Results of our experiments indicated that the incremental recovery is a strong function of emulsion type, emulsion viscosity, and the droplet size distribution.
Deepest Deployment Of Riserless Dual Gradient Mud Recovery System In Drilling Operation In The North Sea
Authors: Claudey Eric , Maubach Caroline , Ferrari Sandy 
Published: March 2016

Abstract
Riserless Dual Gradient Drilling (DGD) using a specialized subsea pump placed on the seafloor during top hole drilling has been widely used on offshore subsea wells prior to installing the blow out preventer (BOP). Riserless DGD systems, kown as riserless mud recovery (RMR), have been developed to allow riserless sections to be drilled with weighted mud while taking returns back to surface. This allows the operator to set surface casing strings deeper, thereby reducing the total number of liners/casing strings in the well.
This paper addresses the deepest RMR operation on the Norwegian Continental Shelf to date. The water depth was 854m and the 26″ hole section was successfully drilled to 1972mMD (1913mTVD). The riserless mud recovery system enabled the 20″ shoe to be set at a sufficient depth to allow elimination of the 16″ liner, thereby reducing casing strings, cost, well complexity and most importantly setting up the 13-5/8″ string cementation for success. This was mission critical from a well integrity perspective in the context of a big bore 9-5/8″ upper completion. Following the successful drilling of the 26″, the 20″ casing was installed and cemented. Foam cement was pumped using the riserless mud recovery system in cuttings transfer mode to prevent accumulation of returned cement at the well head. The 20″ casing was successfully tested after installing the BOP and marine riser.
The paper describes the riserless mud recovery equipment and the planning of the well, plus the engineering of a multi-stage subsea pump and the subsequent seabed deployment in order to drill the longest and deepest 26″ section on the field. A 26″ directional BHA with a 1.30sg surface mud weight (1.18sg downhole mud weight) KCL glycol mud at flow rates of up to 4800 lpm was used to drill to TD. At TD the well was circulated at a lower rate to 1.38sg surface mud weight at 3200lpm to provide trip margin over the effective mud density required for wellbore stability.
Perched Water Static Model
Authors: Rolfsvåg Trond A. , Danielsen Thomas M. 
Published: March 2016

Abstract
Perched water occurs when oil invades a reservoir and eventually traps pools of water at the bottom of the reservoir. The pools of perched water are separated laterally. When the reservoir is unsegmented and in equilibrium, with both water and oil being continuous phases, the saturation curves have to be identical in the upper part of the reservoir. However, the water pressure is increased inside the trap due to the push of the invading oil. As long as the reservoir rock is water-wet, water will try to escape the trap through the continuous water film on the rock surface. The escaping water will have to overcome the capillary pressure building up from the new shallow free water level inside the perched water pool. The perched water pool will become stable at an elevated pressure compared to the water in the main body of the reservoir.
Observing 2nd Mode of Torsional Vibration of the Drill String Using a High Resolution Downhole Data Recorder
Authors: Corrie G. , Jeffrey C. , Keshiyev S. 
Published: March 2016

Abstract
A rarely recorded drilling harmonic is noted to have occurred in two North Sea applications. Torsional vibration at the second harmonic frequency of the drill string has been recorded and validated with the aid of Finite Elemenet Analysis (FEA). Heavy wear to the drill pipe hardbanding was observed in one well which is believed to be related to the second harmonic torsional vibration.
Although Stick-Slip during drilling is fairly common, little is done to understand the frequency of the Stick-Slip cycle. The typical model assumes string RPM to be constant at surface with greatest variation at the bit (first harmonic frequency). However analysis of downhole data has shown this is not always the case. Torsional vibration or Stick-Slip is typically relatable to the first harmonic frequency of the drill string, i.e. maximum RPM variance occurs at one point only (the bit). For the system to enter the second harmonic frequency (two points of maximum RPM variance) there should be an additional excitation factor. In the two wells analysed there are notably high contact forces in the casing around the upper anti-node of the drill string. It is understood that the high force of the string acting against the wellbore can create a reactive torque large enough to excite the system into the second torsional harmonic. The high contact forces can be attributed to areas of high dog leg severity (DLS) at this point in the well. Although the DLS may not be exceptionally high, its position higher up in the well is of critical importance. This is due to the magnitude of tension in the pipe at this depth created by the weight of the string below. The combination of high tension in the pipe and deviation in the well path will provide contact forces high enough to create the shift from first to second torsional mode.