bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Oil Recovery in Offshore Heavy Oil Underlain by Large Aquifer
Authors: Qin Wenting , Luo Pingya , Wojtanowicz Andrew K. 
Published: March 2016

Abstract
Many offshore heavy oil reservoirs underlain by large aquifer are developed through cold production method: horizontal wells, with water coning/cresting being a major concern. Inflow Control Devices (ICDs) are often used to delay the water breakthrough by balancing the well inflow along the well section. However, ICDs have difficulties to mitigate the water coning/cresting after water breakthrough, leading to water bypass oil, premature well abandonment and low oil recovery. In this study, we propose the use of a dual completion technology, Bilateral Water Sink (BWS), assisted with ICDs to mitigate water coning/cresting in high water cut wells, therefore improving oil recovery for offshore heavy oil underlain by large aquifer.
To investigate the reservoir performance under this new production technique, a series of experiments were conducted in a scaled Hele-Shaw model, similar to a cross-section of horizontal wells. Identical flow behavior at each cross-section perpendicular to the well axis were assumed. The experiments resemble to the situation in which the ICDs have been successfully implemented to provide a uniform flow along the entire well section. The oil recovery, water cut and reservoir pressure were measured in each runs to quantify the effects of BWS wells on water coning/cresting mitigation and improving oil recovery.
The experimental results show that while ICDs mitigate the non-uniform production profile along the horizontal well section, BWS wells mitigate the water coning/cresting by dynamically modifying the pressure distribution in the reservoir. Experimental results also verify that the previously derived theoretical rates in BWS can efficiently suppress the water coning/cresting after water breakthrough. The quantitative and qualitative results demonstrate that BWS could reduce the water cut from over 95% in high water cut horizontal wells to less than 40 % and improve the heavy oil recovery about 4-6 times compared with that of conventional horizontal wells.
Those findings provide a new insight into offshore heavy oil production mechanism. Because of BWS's ability of converting an original bottom water drive system to a more effective edge water drive system, low water cut and high oil recovery can be achieved by utilizing the reservoir energy without using of heat.
Nanoparticle-Stabilized Emulsions for Improved Mobility Control for Adverse-mobility Waterflooding
Authors: Kim Ijung , Worthen Andrew J. , Lotfollahi Mohammad , Johnston Keith P. , DiCarlo David A. , Huh Chun 
Published: March 2016

Abstract
The immense nanotechnology advances in other industries provided opportunities to rapidly develop various applications of nanoparticles in the oil and gas industry. In particular, nanoparticle has shown its capability to improve the emulsion stability by generating so-called Pickering emulsion, which is expected to improve EOR processes with better conformance control. Recent studies showed a significant synergy between nanoparticles and very low concentration of surfactant, in generating highly stable emulsions. This study's focus is to exploit the synergy's benefit in employing such emulsions for improved mobility control, especially under high-salinity conditions.
Hydrophilic silica nanoparticles were employed to quantify the synergy of nanoparticle and surfactant in oil-in-brine emulsion formation. The nanoparticle and/or the selected surfactant in aqueous phase and decane were co-injected into a sandpack column to generate oil-in-brine emulsions. Four different surfactants (cationic, nonionic, zwitterionic, and anionic) were examined, and the emulsion stability was analyzed using microscope and rheometer.
Strong and stable emulsions were successfully generated in the combinations of either cationic or nonionic surfactant with nanoparticles, while the nanoparticles and the surfactant by themselves were unable to generate stable emulsions. The synergy was most significant with the cationic surfactant, while the anionic surfactant was least effective, indicating the electrostatic interactions with surfactant and liquid/liquid interface as a decisive factor. With the zwitterionic surfactant, the synergy effect was not as great as the cationic surfactant. The synergy was greater with the nonionic surfactant than the zwitterionic surfactant, implying that the surfactant adsorption at oil-brine interface can be increased by hydrogen bonding between surfactant and nanoparticle when the electrostatic repulsion is no longer effective.
In generating highly stable emulsions for improved control for adverse-mobility waterflooding in harsh-condition reservoirs, we show a procedure to find the optimum choice of surfactant and its concentration to effectively and efficiently generate the nanoparticle-stabilized emulsion exploiting their synergy. The findings in this study propose a way to maximize the beneficial use of nanoparticle-stabilized emulsions for EOR at minimum cost for nanoparticle and surfactant.
Experimental Studies and Modeling of Foam Hysteresis in Porous Media
Authors: Lotfollahi Mohammad , Kim Ijung , Beygi Mohammad R. , Worthen Andrew J. , Huh Chun , Johnston Keith P. , Wheeler Mary F. , DiCarlo David A. 
Published: March 2016

Abstract
The use of foam in gas enhanced oil recovery (EOR) processes has the potential to improve oil recovery by reducing gas mobility. Nanoparticles are a promising alternative to surfactants in creating foam in the harsh environments found in many oil fields. We conducted several CO2-in-brine foam generation experiments in Boise sandstones with surface-treated silica nanoparticle in high-salinity conditions. All the experiments were conducted at the fixed CO2 volume fraction (g = 0.75) and fixed flow rate which changed in steps. We started at low flow rates, increased to a medium flow rates followed by decreasing and then increasing into high flow rates. The steady-state foam apparent viscosity was measured as a function of injection velocity.
The foam flowing through the cores showed higher foam generation and consequently higher apparent viscosity as the flow rate increased from low to medium and high velocities. At very high velocities, once foam bubbles were finely textured, the foam apparent viscosity was governed by foam shear-thinning rheology rather than foam creation. A noticeable "hysteresis" occurred when the flow velocity was initially increased and then decreased, implying multiple (coarse and strong) foam states at the same superficial velocity.
A normalized generation function was combined with CMG-STARS foam model to cover the full spectrum of foam flow behavior observed during the experiments. The new foam model successfully captures foam generation and hysteresis trends observed in presented experiments in this study and other foam generation experiments at different operational conditions (e.g. fixed pressure drop at fixed foam quality, and fixed pressure drop at fixed water velocity) from the literature.
The results indicate once foam is generated in porous media, it is possible to maintain strong foam at low injection rates. This makes foam more feasible in field applications where foam generation is limited by high injection rates (or high pressure gradient) that may only exist near the injection well. Therefore, understanding of foam generation, and foam hysteresis in porous media and accurate modeling of the process are necessary steps for efficient foam design in field.
Modeling Relative Permeability Variations in Three-Phase Space
Authors: Kianinejad Amir , Chen Xiongyu , DiCarlo David A. 
Published: March 2016

Abstract
Three-phase relative permeability can vary greatly from two-phase relative permeability as mechanisms such as flow coupling, double displacement, and layer drainage flow regime play a role in three-phase flow. These are on top of the dependency of three-phase relative permeability on two saturations and saturation path/history. The net result is that it is difficult to model/predict relative permeabilities in three-phase space. In this work, we present three-phase oil relative permeability data measured along 11 saturation paths, in a water-wet consolidated (Berea sandstone) and unconsolidated (sandpack) porous media. These saturation paths cover a wide swath of the three-phase saturation space, providing a better physical understanding of the complete three-phase phase space. Three different oils (crude oil, mineral oil, and n-octane) are used in the experiments; the varying viscosities, spreading coefficients, and composition of the oils allows us to investigate the effect of different drainage mechanisms on relative permeability curves. Our data show that there are significant variations between the curves depending on the media, final water saturation, and fluids. In particular, when the media and fluids are held constant, oil relative permeability can vary an order of magnitude at the same oil saturation, depending on the initial condition and water saturation. We find that within each media, all the curves represent a similar shape, but reach to a different residual saturation. This suggests that residual oil saturation is the key parameter in observed relative permeability differences along different saturation paths. We examine this hypothesis with the most common three-phase relative permeability models, i.e. Saturation Weighted Interpolation, Stone I and II, where we vary residual oil saturation to fit the experimental data. We find that if residual oil saturation is used as a fitting parameter, the models predict experimental data well. Otherwise, without varying residual oil saturation, these relative permeability models perform poorly in predicting experimental data.
Results of ASP Pilot in Mangala Field: A Success Story
Authors: Pandey Amitabh , Koduru Nitish , Stanley Matthew , Pope Gary A. , Weerasooriya Upali P. 
Published: March 2016

Abstract
The Mangala field in the state of Rajasthan of western India was the first major oil discovery in the Barmer basin and is the largest discovered oil field in the basin. It contains paraffinic oil with average viscosity of ~15 cp and wax appearance temperature only about 5°C lower than reservoir temperature of 65°C. The initial development plan was a hot waterflood to prevent any in situ wax deposition; recently, though chemical EOR methods have started to play an important role in the development of the field.
A polymer flood pilot was successfully conducted in the field. It was followed by an ASP pilot trial which used the same set of wells. Unlike the polymer pilot, ASP injection was confined to a single continuous sand to reduce interference with nearby wells and to reduce the uncertainty in interpretation of pilot results. A combination of a high molecular weight branched alcohol PO-EO sulfate and a high carbon number sulfonate was selected for the ASP formulation. The selected surfactants functioned well in the desired salinity range and were stable in an aqueous solution up to half a percent higher alkali concentration than the optimal concentration.
The pilot facilities needed to meet a number of challenges arising from using neat surfactants-mainly handling of viscous/gelling material, maintaining accurate dosing rates, maintaining the right ratio of two surfactants, and maintaining stability of the sulfate itself. These challenges were surmounted in the pilot by using a blended surfactant solution, diluted with water, with activity of 24%.
ASP injection led to mobilization of significant volume of oil in the confined 5-spot pattern. The oil-cut of the central producer increased from 10% to 80%. The oil production rate showed almost an eight fold increase from 50 bopd to nearly 400 bopd. The estimated incremental recovery over polymer flooding is nearly 20% of the pilot STOIIP. Later in the pilot project the expected increase in water-cut was accompanied with the production of the injected chemicals along with rise in the pH of the produced water, indicating that favourable mobility was maintained during ASP injection. Some production challenges were encountered—most notably the failure of the producer's electrical submersible pump (ESP); this required the producer to be put on jet pump intermittently when the ESP was not functioning. The saturation observation wells located within the pattern area showed significant desaturation of oil. Sponge cores acquired after the pilot showed very low remaining oil saturation in the flooded sections. The paper will discuss the pilot operations, monitoring and quality control, the pilot results, and lessons learnt.
Interwell ASP Pilot Design for Kuwait's Sabriyah-Mauddud
Authors: Fortenberry R. , Delshad M. , Suniga P. , Koyassan Veedu F. , Wang P. , Al-Kaaoud H. , Singh B. B. , Tiwari S. , Baroon B. , Pope G. A. 
Published: March 2016

Abstract
Our team has developed a new simulation model for an upcoming 5-spot Alkaline-Surfactant-Polymer (ASP) pilot in the Sabriyah Mauddud reservoir in Kuwait. We present new pilot simulation results based on new data from pilot wells and an updated geocelluar reservoir model. New cores and well logs were used to update the geocellular model, including initial fluid distributions, permeability and layer flow allocation.
From the updated geocellular model a smaller dynamic sector model was extracted to history match field performance of a waterflood pattern. From the dynamic model a yet smaller pilot model was extracted and refined to simulate the 5-spot ASP pilot.
We used this pilot model to evaluate injection composition, zonal completions, observation well locations, interwell tracer test design and predicted performance of ASP flooding. A sensitivity analysis for some important design variables and pilot performance benchmarks is also included. We used multiple interwell tracer test simulations to estimate reservoir sweep efficiency for both water and ASP fluids, and to help us understand how well operations will affect this unconfined ASP pilot. This work details some crucial aspects of pre-ASP pilot design and implementation.
Compositional Modeling of Enhanced Hydrocarbons Recovery for Fractured Shale Gas-Condensate Reservoirs with the Effects of Capillary Pressure and Multicomponent Mechanisms
Authors: Jiang Jiamin , Younis Rami M. 
Published: March 2016

Abstract
There is considerable and timely interest in oil and condensate production from liquid-rich regions, placing emphasis on the ability to predict the behavior of gas condensate bank developments and saturation dynamics in shale gas reservoirs. As the pressure in the near-wellbore region drops below the dew-point, liquid droplets are formed and tend to be trapped in small pores. It has been suggested that the injection of CO2 into shale gas reservoirs can be a feasible option to enhance recovery of natural gas and valuable condensate oil, while at the same time sequestering CO2 underground. This work develops simulation capabilities to understand and predict complex transport processes and phase behavior in these reservoirs for efficient and environmentally friendly production management.
Although liquid-rich shale plays are economically producible, existing simulation techniques fail to include many of the production phenomena associated with the fluid system that consists of multiple gas species or phases. In this work, we develop a multicomponent compositional simulator for the modeling of gas-condensate shale reservoirs with complex fracture systems. Related storage and transport mechanisms such as multicomponent apparent permeability (MAP), sorption and molecular diffusion are considered. In order to accurately capture the complicated phase behavior of the multiphase fluids, an equation of State (EOS) based phase package is incorporated into the simulator. Due to the large capillary pressure that exists in the nanopores of ultra-tight shale matrix, the phase package considers the effect of capillary pressure on phase equilibrium calculations. A modified negative-flash algorithm that combines Newton's method and successive substitution iteration (SSI) is used for phase stability analysis under the effect of capillary pressure between oil and gas phases.
In addition, a lower-dimensional discrete fracture and matrix (DFM) model is implemented. The DFM model is based on unstructured gridding, and can accurately and efficiently handle the non-ideal geometries of hydraulic fracture in stimulated unconventional formation. Optimized local grid refinement (LGR) is employed to capture the extremely sharp potential gradient and saturation dynamics in the ultra-tight matrix around fracture.
We apply the developed simulator to study the combined effects of capillary pressure and multicomponent storage and transport mechanisms that are closely associated with the phase behavior and hydrocarbon recovery in gas-condensate shale reservoirs. We present preliminary simulation studies to show the applicability of CO2 huff-n-puff for the purpose of enhanced hydrocarbons recovery. Several design components such as the number of cycles and the length of injection period in the huff-n-puff process are also briefly investigated.
Optimized Cement Systems and Placement Techniques for Tight Clearance Liners
Authors: Verbakel Roeland , Salazar Jose , van Aerssen Mark 
Published: March 2016

Abstract
In a challenging well in a mature gas field offshore Germany, four different size liners with annular clearance of less than 1-in. with the open hole or previous casing were cemented. Successful cementing of these liners was critical in order to drill and complete the well before putting it into production.
To avoid lost circulation during cementing, we established loss-free mud circulation rates before the cementing operation and designed cement slurries with long thickening times for placement at low rates. Additionally, we used fibers in the cement slurry, and pumped treated micronized barite drilling fluid ahead of the cement slurry to lower friction pressures and optimize mud removal.
We validated cement slurry designs through a rigorous laboratory testing procedure, including go/no-go procedures in the high temperature/high pressure (HPHT) consistometer. Long thickening times were needed, especially on a 600 m long 6-in. expandable liner cement job. We tested the setting times of cement accurately with ultrasonic cement analysis and static gel strength analysis devices. Additives to reduce the risk of gas migration were included in all cement slurries.
In order to optimize mud removal and reduce the chance of cement slurry getting contaminated, custom made centralizers were strategically placed in highly critical areas. We optimized spacers through a full laboratory analysis of compatibility between spacer and the low-toxic oil based mud, as well as performing reverse emulsion and grid tests. We validated the mud removal design with 2-D simulations to predict the effectiveness of mud displacement from the wellbore.
Cement slurry was placed without losses on all liners. In all cases, we had positive indications that cement slurry reached up to the liner hanger by observing cement slurry in the returns back to surface. All formation integrity tests on the liner shoe were successful and allowed drilling of the consecutive section. The final production liner was logged using a radial bond tool and advanced cement evaluation processing was run on the data in order to better evaluate cement quality. Good cement bond quality was observed behind the production liner.
Visualization and Quantification of Fluid Flow through Degraded Cement Sheaths
Authors: Skorpa Ragnhild , Vrålstad Torbjørn 
Published: March 2016

Abstract
Cement sheath integrity is important to maintain zonal isolation, as the annular cement sheath is considered to be one of the most important well barrier elements in the well, both during production and after well abandonment. It is however well known that cement sheaths degrad over time, e.g. from repeated temperature variations during production, but the link between the actual leakage rate and the degradation of cement sheaths have not yet been established.
In this paper, we have mapped actual leak paths of degraded cement sheaths, created by thermal cycling experiments, by X-Ray Computer Tomography (CT). The resulting leak path was imported into a Computational Fluid Dynamics (CFD) simulation software, making it possible to determine flow rates of various fluids through actual degraded cement sheaths. The pressure drop over the cement sheath was used as boundary condition of the system. Pressure driven flow through two degraded cement shetats was studied using methane gas as model fluid. The degree of degradation of the cement sheaths varied from systematically connected cracks to real microannuli. The flow through a system of connected cracks compared to a flow through true micro annuli was found to differ by orders of magnitude.
Dynamic Simulation of Gas Migration in Marine Risers
Authors: Velmurugan Naveen , Godhavn John-Morten , Hauge Espen 
Published: March 2016

Abstract
The main objective of this work is to study the dynamic behavior of gas expansion in marine risers. The term ‘riser equilibrium' is used to provide a more rational explanation of gas expansion and its relation to riser unloading. While handling a gas kick situation with the blowout preventer closed, the gas within the riser expands until its pressure equals the hydrostatic pressure of the mud column above, plus any applied back pressure. Buoyancy or slip will cause the gas to migrate, which in turn will cause further expansion, if allowed to, or an increase in pressure. But after a certain point, termed as ‘Riser Equilibrium Point', any small decrease in the hydrostatic pressure would trigger the gas to expand rapidly until enough back pressure is applied or the top of the gas reaches surface. This could cause an explosive unloading. Complete dissolution of gas in oil based muds and the relative delay in noticing any surface indications for the gas influx makes influx detection more complicated with oil based mud as opposed to water based mud. Estimation of various parameters to study these phenomena and their correlation to the gas expansion is studied through an analytical and iterative approach. All schemes are implemented in Matlab and give a basic understanding of the severity of the situation. Calculation of the riser equilibrium point is beneficial to understand the risks related to riser unloading and riser collapse through proper estimation of collapse load. Since the conventional ‘free gas' approach to calculate surface volume of gas during kill operations tend to overestimate the risks involved, this study is expected to provide a more comprehensive understanding of the situation providing a safer operational conditions to handle gas in risers.