bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Low-Cost Dilute Surfactants on Wettability and Relative Permeability
Authors: Rao D. N. , Ayirala S. C. , Abe A. A. , Xu W. 
Published: December 2007

Abstract
The decline of surfactant flooding can be attributed to the expense of reducing oil-water interfacial tension by several orders of magnitude. This study examines the potential for enhancing oil recovery by using low-cost surfactants to alter wettability. The wettability alterations by the surfactants have been characterized using contact angles and oil-water relative permeabilities. Core flooding experiments were conducted using three different rock-fluids systems: (1) Berea sandstone, Yates stocktank crude oil, Yates synthetic brine; (2) Yates dolomite rock, Yates stocktank crude oil, Yates synthetic brine; and (3) Yates dolomite rock, Yates live crude oil, Yates synthetic brine. Two types of surfactants, one nonionic and the other anionic have been used for wettability alteration. The experiments with Berea were conducted at ambient conditions, while dolomite rock tests were conducted at Yates reservoir conditions of 82°F and 700 psi. Contact angles were measured using Yates reservoir fluids and dolomite crystal surfaces using the Dual-Drop Dual-Crystal technique and oil-water relative permeabilities were computed by history matching oil recovery and pressure drop data from the coreflood experiments.
The shifts in relative permeability ratio curves indicate the ability of both surfactants to develop mixed-wettability in Berea sandstone cores. In the Yates dolomite rock, Yates stocktank oil and Yates brine system, both surfactants altered wettability from an initially strongly oil-wet to a weakly oil-wet state. For Yates live oil containing rock-fluids system, the nonionic surfactant altered the wettability from an initial weakly water-wet to a mixed-wet state, while anionic surfactant resulted in wettability alterations to a strongly oil-wet state. The contact angle measurements corroborated well with oil-water relative permeabilities to confirm the wettability shifts except for Yates live oil containing system with nonionic surfactant, where contact angles indicated wettability alterations to an intermediate-wet state. This study thus demonstrates the relative benefits of surfactant-induced wettability alteration mechanism to develop either intermediate or mixed wettability in reservoir rock-fluids for significant oil recovery enhancements.
A Study of Wetting Behavior and Surfactant EOR in Carbonates With Model Compounds
Authors: Wu Y. , Shuler P. J. , Blanco M. , Tang Y. , Goddard W. A. 
Published: December 2007

Abstract
This study focuses on the mechanisms responsible for enhanced oil recovery (EOR) from fractured carbonate reservoirs by surfactant solutions, and methods to screen for effective chemical formulations quickly. One key to this EOR process is the surfactant solution reversing the wetting of the carbonate surfaces from oil-wet to water-wet conditions. This effect allows the aqueous phase to imbibe into the matrix spontaneously and expel oil bypassed by a waterflood.
This study used different naphthenic acids (NA) dissolved in decane as a model oil to render calcite surfaces oil-wet. Because pure compounds are used, trends in wetting behavior can be related to NA molecular structure as measured by solid adsorption, contact angle and a novel, simple flotation test with calcite. Experiments with different surfactants and NA-treated calcite powder provide information about mechanisms responsible for sought after reversal to a water-wet state. Results indicate this flotation and a calcite chip cleaning test are rapid screening tools to identify better EOR surfactants for carbonates.
The study considers the application of surfactants for enhanced oil recovery (EOR) from carbonate reservoirs. This technology provides a new opportunity for EOR, especially for fractured carbonate where waterflood response typically is poor and the matrix is a high oil-saturation target for this process.
Mechanistic Study of Interaction between Water and Carbonate Rocks for Enhancing Oil Recovery
Authors: Gomari K. A. R. , Karoussi O. , Hamouda A. A. 
Published: December 2007

Abstract
The aim of this paper is to demonstrate the important role of ion composition for successful oil recovery by water injection and it also suggests possible mechanisms by which different ions interact with the carbonate rocks to alter the wettability.
Injected water contains, among other ions, sulfate and magnesium ions. The possible wettability alteration mechanisms of the calcite surface by Mg2+ and SO42- to more water-wet is addressed in light of contact angle measurements, and surface potential.
Combustion Front Behavior in Porous Media With Catalytic Agents
Authors: Adagulu G. D. , Akkutlu I. Y. 
Published: December 2007

Abstract
Several experimental investigations have previously considered naturally occurring clays, metallic minerals and additives as catalytic agents to improve oil recovery during air injection and in-situ combustion processes. It is reported that these materials could change the morphology and surface properties of the porous medium ahead of the combustion front; thus, (1) increase hydrocarbon deposition ahead of the front, and (2) modify the kinetics of oxidation reactions inside the front. However, their on the combustion front dynamics has not previously been investigated under varying reservoir conditions. In this paper, we approach the problem using an analytical method based on large activation energies of the oxidation reactions. The model describes combustion front as a moving boundary layer in a uniform porous medium. It involves coherent propagation of low-temperature (fuel-generating) and high-temperature (fuel-burning) reaction regions under the influence of reservoir heat losses; thus, it is suitable for investigating the role of catalytic agents on the front propagation. In the absence of these materials, it has been previously found that the reaction regions propagate closely spaced, thus reducing the influence of deleterious heat losses on the combustion front [6,7]. At low air injection rates, however, the peak temperature and propagation velocity of the front noticeably decrease; namely, the front approaches its extinction limit. Here, we propose that any possible improvement (whether catalytic or not) on combustion performance should preclude the observed temperature drop with the low injection rates. The presence of catalytic agents is consequently introduced to the model in terms of systematic variations in the reaction kinetics parameters, and deposited hydrocarbon/generated fuel amounts. It is found that, although kinetics influences the system dynamics, it may not improve the combustion performance due to a compensation effect. The improvement is rather due to an implicit role of the increased specific sand grain surface area on the hydrocarbon deposition ahead. The surface area promotes fuel deposition; hence, significantly increase total heat content of the combustion process in the reservoir. The work is important for developing guidelines to screen catalytic agents that could be used during the air injection processes.
Laboratory Experiments of Tertiary CO2 Injection Into a Fractured Core
Authors: Darvish G. R. , Lindeberg E. , Holt T. , Utne S. A. 
Published: December 2007

Abstract
The efficiency of tertiary CO2 injection at the reservoir conditions into fractured cores has been investigated experimentally. The experiment was designed to illustrate the process of water imbibition and CO2 injection into a North Sea chalk reservoir.
The core and core holder assembly were designed to allow a 2 mm gap to surround the core simulating a fracture. Live reservoir oil was prepared and used to saturate the matrix system. Due to the large permeability contrast between the core (4 mD) and the fracture it is not feasible to saturate the core by simply flooding the system with live oil, since oil would flow through the fracture and only partially saturate the core. To overcome this problem a unique technique has been developed for saturating the matrix system with reservoir fluids. This method ensures a homogeneous fluid composition within the pore system before the fracture system is initialized by the injection fluids (water/CO2).
During the experiment, the matrix system was first saturated with the live reservoir oil, during which the gap was blocked by a sealing material. In the next step the sealing material was removed and water was injected into the gap. Finally CO2 was injected at a low and constant rate into the gap. Oil and water production and fluid composition were monitored and the results show that injection of CO2 could significantly recover residual oil after water injection.
Development of Surrogate Reservoir Models (SRM) for Fast-Track Analysis of Complex Reservoirs
Authors: Mohaghegh S. D. , Modavi A. , Hafez H. H. , Haajizadeh M. , Kenawy M. , Guruswamy S. 
Published: December 2007

Abstract
Reservoir simulation has become the industry standard for reservoir management. It is now used in all phases of field development in the oil and gas industry. The full field reservoir models that have become the major source of information and prediction for decision making are continuously updated and major fields now have several versions of their model with each new version being a major improvement over the previous one. The newer versions have the latest information (geologic, geophysical and petro-physical measurements, interpretations and calculations based on new logs, seismic data, injection and productions, etc.) incorporated in them along with adjustments that usually are the result of single-well or multi-well history matching.
A typical reservoir model consists of hundreds of thousands and in many cases millions of grid blocks. As the size of the reservoir models grow the time required for each run increases. Schemes such as grid computing and parallel processing helps to a certain degree but cannot close the gap that exists between simulation runs and real-time processing. On the other hand with the new push for smart fields (a.k.a. i-fields) in the industry that is a natural growth of smart completions and smart wells, the need for being able to process information in real time becomes more pronounced. Surrogate Reservoir Models (SRMs) are the natural solution to address this necessity. SRMs are prototypes of the full field models that can run in fractions of a second rather than in hours or days. They mimic the capabilities of a full field model with high accuracy. These models can be developed regularly (as new versions of the full field models become available) off-line and can be put online for automatic history matching and real-time processing that can guide important decisions. SRMs can efficiently be used for real-time optimization, real-time decision making as well as analysis under uncertain conditions.
This paper presents a unified approach for development of SRMs using the state-of-the-art in intelligent systems techniques. An example for developing an SRM for a giant oil field in the Middle East is presented and the results of the analysis using the SRM for this field is discussed. In this example application SRM is used in order to analyze the impact of the uncertainties associated with several input parameters into the full field model.
Dynamics of Two-Phase Immiscible Pulsed Flow
Authors: Ivanov D. A. , Araujo M. 
Published: December 2007

Abstract
Cyclic waterflooding has received recent attention since many studies and field tests have shown that it may lead to additional oil recovery at virtually zero additional cost. Even though the process is in principle very similar to conventional waterflooding, there are interesting new effects taking place under the pulsed conditions that need to be properly quantified for a realistic field deployment of the cyclic injection process.
Two-phase immiscible pulsed flow experiments performed on homogenous packed glass beads cells are compared with flow behaviour under continuous injection. In the pulsed experiments, injection is switched on/off using a timing device in the pumping system. Symmetric cyclic periods and different injection rates were used in the study. Initially the dry packed cells were flushed with CO2 and saturated with water. This was followed by injection of oil up to leaving the cells at irreducible water saturation conditions. Then water was injected and the amount of produced fluids measured. Separate experiments under continuous and pulsed injection conditions with visual monitoring of fluid displacement were performed.
It is found that the amount of oil recovered at intermediate stages (after breakthrough and less than 3 pore volumes of injected water) is larger for the pulsing mode. The final recovery for both injection processes is similar within the experimental error. In the pulsed experiments, during the off injection period, spontaneous fluid spreading was observed leading to smoother displacement fronts compared to continuous injection. Also, displacement fronts were found to be more stable under pulsed conditions. The study concludes that residual oil saturation under pulsed injection can be reached earlier than under continuous injection, a result very attractive for field application. Experimental findings of this work shed light in the design of cyclic injection processes.
Identification of the Source of Low-Salinity Water Produced from a Subsea Well in the Birch Field and Implications for Scale Management
Authors: McCartney R. A. , Coghlan G. , White A. 
Published: December 2007

Abstract
Interpretation of produced water analyses is a relatively inexpensive method of obtaining a wide range of information that can be used to aid scale management, constrain the reservoir model, provide information on barriers to flow and zones of connectivity in the reservoir, and identify zones of water production in wells. In this paper we report on the interpretation of produced water analyses to help understand why unusual low salinity water was produced from well Z3, a sub-sea well in the Birch Field with two production zones (Brae Conglomerate and Ryazanian Sandstone), when production was re-started in March 2004 after a three-year shut-in period. In this case, of particular interest were the implications for future scale management on the well.
We have shown that the low salinity water is likely to be formation water from the Ryazanian Sandstone. Production of this water from well Z3 is declining over time, which may reflect the limited extent of the Ryazanian Sandstone, a nearby barrier to flow or calcium carbonate deposition adjacent to the well during pressure drawdown. Future water production from well Z3 is expected to be dominated by production from the Brae Conglomerate with production from the Ryazanian Sandstone only being important after lengthy shut-in periods. Current squeeze treatments are based on pre-development scaling predictions and have been designed to prevent moderate barite deposition. These treatments are likely to mitigate the mild barite scale deposition predicted to be associated with future production of water from the Brae and Ryazanian intervals. As the future scaling potential is predicted to be much less than originally planned for, the possibility of reducing the current MIC or discontinuing future squeeze treatments is being considered. Further work is required to fully assess the carbonate scaling risk associated with mixing of these waters but there are currently no indications that carbonate scale is forming in the well.
This study has demonstrated the value of interpretation of routinely collected produced water analyses in that it helped us understand and act on significant changes in produced water compositions from a sub-sea well without resorting to an expensive well intervention.
Near-Critical Gas/Condensate Relative Permeability of Carbonates
Authors: Calisgan H. , Demiral B. , Akin S. 
Published: December 2007

Abstract
The productivity of most gas condensate wells is reduced significantly due to condensate banking when the bottom-hole pressure falls below the dew point. The liquid drop-out such gas wells leads to reduced gas relative permeability and thus to low recovery problems. An understanding of the characteristics of the high-velocity gas-condensate flow and relative permeabilities is necessary for accurate forecast of well productivity. In order to tackle this goal, a series of relative permeability measurements on a moderate permeability carbonate core, using a binary retrograde condensate fluid sample were conducted near miscible conditions. The experiments used a pseudo-steady-state technique at high pressure and high velocity, measuring relative permeability under conditions similar to the near well region of a carbonate gas-condensate reservoir. Furthermore, the flow of gas and condensate at different force ratios (capillary and bond numbers) are investigated. It was observed that relative permeability depended on fluid composition and flow rate as well as condensate and water saturations. It was observed that as the flow rate of wetting phase (condensate) increased or the interfacial tension decreased, relative permeability curves shifted to left. It was found that a simple three-parameter mathematical model that depends on a new dimensionless number called condensate number successfully models the gas-condensate relative permeability data. The developed model resulted in a good agreement with published gas-condensate relative permeability data as well as end point relative permeabilities and saturations.
Gas/Water Flow in Porous Media in the Presence of Adsorbed Polymer: Experimental Study on Non-Darcy Effects
Authors: Blanchard V. , Lasseux D. , Bertin H. , Pichery T. , Chauveteau G. , Tabary R. , Zaitoun A. 
Published: December 2007

Abstract
The mechanism of Disproportionate Permeability Reduction (DPR) resulting from polymer or gel adsorption in porous media has been widely reported in the literature in the domain of Darcy regime. However, very few studies have been dedicated to the impact of polymer adsorption in porous media when two-phase flow occurs in non-linear regimes which are of interest in a wide range of applications. The objective of this paper is to report some experimental investigations on the effect of polymer adsorption on gas-water flow at low mean pressure, i.e. when Klinkenberg effects (or gas slippage) must be considered, as well as at high flow rates when inertial effects are significant.
The experimental study reported in this paper consists of water and nitrogen injections into various silicon carbide model granular packs having different permeabilities. More specifically, the purpose is to investigate gas flow at different water saturations before and after polymer adsorption over flow regimes ranging from slip flow to inertial flow. In good agreement with previous works, in the Darcy regime, we observe an increase in irreducible water saturation and a strong reduction in the relative permeability to water while the relative permeability to gas is slightly affected. At low mean pressure in the gas phase, the magnitude of Klinkenberg effect is found to increase with water saturation in the absence of polymer, whereas, for the same water saturation, the presence of an adsorbed polymer layer reduces this effect. In the inertial regime, a reduction of inertial effects is observed when gas is injected after polymer adsorption, taking into account water saturation and permeability modifications. Experimental data are discussed according to hypotheses put forth to explain these effects.
Generalized Horizontal Well Inflow Relationships for Liquid, Gas, or Two-Phase Flow
Authors: Kamkom R. , Zhu D. 
Published: December 2007

Abstract
The analytical models for horizontal inflow performance relationships (IPR) are presented in this paper for different formation fluid types and different boundary conditions. Even though reservoir simulation models may give more accurate and detailed results of oil and gas well production, analytical models are commonly used in the field for quick, practical and reasonable estimation of well performance. The analytical models are especially attractive when working on single well design and performance optimization. Similar to vertical well models, the analytical models for horizontal wells are developed for specific conditions. The IPR equations for horizontal wells are categorized into two boundary conditions; the steady-state flow condition (constant boundary pressure) and the pseudo-steady-state flow condition (no flow at the boundary). For each condition, the IPR equations for oil and gas wells are presented. Two-phase flow correlations for horizontal well IPR are also presented for the pseudo-steady- state condition. The results from different models are compared in the paper, and the limitations and appropriate applications of the IPR equations are discussed in the paper.
For each fluid system, examples illustrate how flow behavior varies with the flow regime. Examples also show the effect of critical parameters on inflow performance for horizontal wells. These equations are invaluable for reservoir and production engineers in their daily practice in horizontal wells.
Increasing Oil Recovery by Preventing Early Water and Gas Breakthrough in a West Brae Horizontal Well: A Case History
Authors: Mclntyre A. , Adam R. , Augustine J. , Laidlaw D. 
Published: December 2007

Abstract
Inflow control devices, which prevent early water breakthrough by passively controlling the inflow profile of a well, have had a long and successful history in the Norwegian Sector of the North Sea and in Saudi Arabia. This paper will document the first application of inflow control devices in the UK sector of the North Sea.
This application took place on a 4,288 ft horizontal sidetrack of a well in the West Brae field. The completion was designed for a homogeneous permeability but the as-drilled permeability, as shown by logging-while-drilling data, had very high permeability regions in the heel of the horizontal, and lower permeability in the toe. If conventional completion methods (i.e. stand-alone screens, gravel packs, or expandable screens) were used, the result would likely have been early water breakthrough and well abandonment. The authors will highlight the inflow control device selection process, integrated completion and reservoir analysis, well completion operations summary, and production results and predictions. The successful application of inflow control devices on this well illustrates that long horizontal wells can be completed, the problem of early water and gas breakthrough can be prevented, and oil recovery can be increased by using inflow control devices.