bluuebunny/crossref_metadata_2025_split huggingface dataset:
Two-Stage Upscaling of Two-Phase Flow: From Core to Simulation Scale
Authors: Lohne Arild , Virnovsky George , Durlofsky Louis J. 
Published: December 2007

Abstract
In the coarse scale simulation of heterogeneous reservoirs, effective or upscaled flow functions, e.g., oil and water relative permeability and capillary pressure, can be used to represent heterogeneities at subgrid scales. The effective relative permeability is typically upscaled along with absolute permeability from a geostatistical model. However, the potentially important effects of smaller scale heterogeneities (on the centimeter to meter scale) in both capillarity and absolute permeability will not be captured by this approach.
In this paper, we present a new two-stage upscaling procedure for two-phase flow. In the first stage, we upscale from the core (fine) scale to the geostatistical (intermediate) scale, while in the second stage we upscale from the geostatistical scale to the simulation (coarse) scale. The computational procedure includes numerical solution of the finite difference equations describing steady state flow over the local region to be upscaled, using either constant pressure or periodic boundary conditions.
The two-stage method is applied to synthetic two-dimensional reservoir models with strong variation in capillarity on the fine scale. Results are presented in terms of both oil production rates and saturation fields. Accurate reproduction of the fine grid solutions (simulated on 500 × 500 grids) is achieved on coarse grids of 10 × 10 for different flow scenarios. It is shown that, although capillary forces are important on the fine scale, the assumption of capillary dominance in the first stage of upscaling is not always appropriate, and that the computation of rate dependent effective properties in the upscaling can significantly improve the accuracy of the coarse scale model. The assumption of viscous dominance in the second upscaling stage is found to be appropriate in all of the cases considered.
Wettability Alteration During Surfactant Flooding of Carbonate Reservoirs
Authors: Seethepalli A. , Adibhatla B. , Mohanty K. K. 
Published: December 2007

Abstract
Recovery from fractured, oil-wet/mixed-wet, carbonate reservoirs by waterflooding is poor. Dilute surfactant methods are being developed to improve oil recovery from fractured carbonates. This paper investigates the interactions of dilute alkaline anionic surfactant solutions with crude oil on carbonate mineral surfaces. Wettability, phase behavior, interfacial tension and adsorption experiments have been conducted. Anionic surfactants have been identified which can change the wettability of the calcite surface to intermediate/water-wet condition as well or better than the cationic surfactant DTAB with a West Texas crude oil. All the carbonate surfaces (Lithographic Limestone, Marble, Dolomite and Calcite) show similar behavior with respect to wettability alteration with an anionic surfactant. Anionic surfactants, which lower the interfacial tension with the crude oil to very low values (&lt;10−2 mN/m), have also been identified. The adsorption of the sulphonate surfactants can be suppressed significantly by the addition of the alkali.
Physically-Based Capillary Pressure Correlation For Mixed-Wet Reservoirs From A Bundle-Of-Tubes Model
Authors: Helland J. O. , Skjæveland S. M. 
Published: December 2007

Abstract
It is shown that the main characteristics of mixed-wet capillary pressure curves with hysteretic scanning loops can be reproduced by a bundle-of-triangular-tubes model. Accurate expressions for the entry pressures are employed, truly accounting for the mixed wettability and the diverse fluid configurations that arise from contact angle hysteresis and pore shape. The simulated curves are compared with published correlations that have been suggested by inspection of laboratory data from core plug experiments.
Development and Application of a New Technique for Upscaling Miscible Processes
Authors: Hui Mun-Hong , Zhou Dengen , Wen Xian-Huan , Durlofsky Louis J. 
Published: December 2007

Abstract
Miscible gas injection offers both high local displacement efficiencies and a means for handling produced gas. As fine scale simulations of miscible processes can be very time-consuming, there is a clear need for an accurate and robust coarse scale miscible simulation capability. In this paper, we present a new upscaling technique for the accurate coarse scale simulation of first-contact miscible displacements. Our method contains two key components: Effective Flux Boundary Conditions (EFBCs) and the Extended Todd & Longstaff with Pseudo relative permeabilities (ETLP) formulation. EFBCs, which were applied previously within the context of immiscible displacements, account approximately for the effect of the global flow field on the local upscaling problems and as a result mitigate inaccuracies introduced by standard procedures. The ETLP formulation modifies the way effective fluid properties and upscaled relative permeabilities are computed in a limited compositional framework such that residual oil that is immobile and unavailable for mixing is efficiently represented.
The accuracy of the new technique is demonstrated for several example problems. Using synthetic models with differing permeability correlation lengths, we show that the new method provides results superior to those obtained using existing upscaling procedures (standard upscaled relative permeabilities, upscaled absolute permeabilities only, and nonuniform coarsening) for partially layered cases. The breakthrough time, oil production curve and saturation profiles are predicted accurately. The method is also shown to perform well over a wide range of coarsening factors (4 – 2500) for several fields with different permeability heterogeneity structures. Finally, we apply the method to a real field case with encouraging results, indicating the practical applicability of the new technique.
Coiled-Tubing-Conveyed Fracturing Technique Provides Economic Alternative To Workover Rigs in Stimulation Campaign
Authors: Allouti Achour , Amor Bachir Ben , Ferhat Ali , Oettli Mark , Ortiz Avel , Wood Jodi 
Published: December 2007

Abstract
In the moderate-permeability environment of the Hassi Messaoud field of central Algeria, proppant fracturing has significantly increased production, prolonging the economic life of many wells. Unfortunately, the logistics of mobilizing a workover rig to prepare the wellbore for stimulation has extended the stimulation cycle time. Additionally, many wells have tubular problems that require intervention such as squeeze cementing or tubular replacement before the stimulation process can begin. The availability of coiled-tubing equipment in the field provides the means to stimulate the wells without a workover rig. Furthermore, when coupled with a mechanical isolation system, the coiled-tubing fracturing technique protects the production tubing from high treating pressure and abrasive proppants. In the past, the lack of a reliable isolation system has limited the success of these jobs.
Reservoir conditions throughout the field allow low-rate stimulations but induce high bottomhole pressures, which make the use of conventional packers difficult. In many environments the bottomhole treating pressure creates differential pressures across the elements of a packer in excess of 9,000 psi. Several attempts to use existing packer technology yielded unsuccessful fracture treatments, and costly fishing operations were necessary to restore the wells to production. To provide an economical solution to the problems encountered by conventional mechanical packers, a new isolation system was designed. This paper provides case histories of several wells stimulated with coiled-tubing fracturing in the extreme environment of high-pressure, deep wells in the Hassi Messaoud field and examines the engineering challenges in developing a robust isolation system.
Selected U. S. Department of Energy EOR Technology Applications
Authors: Felber Betty J. 
Published: December 2007

Abstract
Enhanced oil recovery (EOR) innovations have paved the way for newer, more exciting technologies that provide improved EOR processes. Among the latest advancements are new methods for describing the reservoir, improved downhole instrumentation, and new chemicals engineered to improve recovery. These are just a few of the innovations available to geoscientists and engineers in their quest for better reservoir description and applications of improved EOR processes.
The U. S. Department of Energy (USDOE) has sustained development of many of these technologies. This paper highlights some of the USDOE championed laboratory and field applications work in steamflooding, biotechnology, alkaline-surfactant-polymer (ASP) formulations and chemicals to increase carbon dioxide viscosity. Future challenges in applying EOR using microhole technology are also discussed.
Advancements in steamflooding include mechanistic studies to better understand fluid and heat flow conditions. The biotechnology work discussed used resident microflora to selectively plug porous zones and increase oil recovery. The alkaline-surfactant-polymer work summarizes the laboratory and field work conducted in support of a shallow reservoir ASP application. The laboratory search for chemicals to increase the viscosity of carbon dioxide is also discussed.
A new area of work is microhole technology—wellbores that are less than 2-¼ inches in diameter. Included in this discussion are the challenges of developing the tools, the market, and the expectation of delivery of improved oil recovery chemicals utilizing a microhole.
A Novel and Successful MEOR Pilot Project in a Strong Water-Drive Reservoir Vizcacheras Field, Argentina
Authors: Strappa L. A. , De Lucia J. P. , Maure M. A. , Llopiz M. L. Lopez 
Published: December 2007

Abstract
The synergy between a novel biotechnological design, streamlines simulation and field-monitoring practices produced successful results in Papagayos formation, a strong water-drive reservoir of Vizcacheras field (Attachment A, Figures 25, 26, 27).
Vizcacheras field (8,636 BOPD, 162 producers) located in Cuyo Basin (Mendoza province, Argentine) started producing in 1965, involving two main reservoirs (Papagayos and Barrancas). The 60% of total Vizcacheras production is coming from Papagayos formation, which has a temperature of 198 °F, an average permeability of 1000 mDarcy, an effective porosity of 25% and residual oil saturations of 25%.
The Microbial Program started in September 1999 by a systematic inoculation in VI-286 injector using hydrocarbon degrading anaerobic-facultative microorganisms. The project was developed for along 19 months of uninterrupted treatment. The MEOR methodology used a novel approach based on low-rate injector wells serving only as a surface-to-reservoir transport link to introduce periodic batches of nutrients, biocatalyzers and microorganisms into the reservoir to colonize the contacted pore volume.
Pre- and Post-MEOR geochemical and rheological evaluations contributed to a better understanding of underlying fluid-rock-biological interactions. Fractional flow alteration in produced fluids has shown a clear improvement: oil increased and water retracted in neighbor producers of treated injector. Three dominant combined mechanisms explain this behavior: 1) further reduction of residual oil saturation by in-situ biosurfactants with low interfacial tension, 2) improved oil mobility from short-chain solvents originated by microbial alteration of heavy paraffinic ends and 3) Conformance efficiency improvement created by the colonizing biomass in active streamtubes that diverts fluids to unflooded zones.
MEOR in Papagayos formation increased the oil production rate 20% in average over baselines and the incremental reserves are estimated in 176 MBO.
The development cost of the pilot reached 2.87 $/BO and is expected to be lower than this value during future scaled stages. The present work includes an overview of the proposed expansion project, which involves two additional patterns and the current pilot injector.
Production Performance Study of West Carney Field, Lincoln County, Oklahoma
Authors: Joshi Rahul , Kelkar Mohan 
Published: December 2007

Abstract
The paper describes a field case study of Hunton formation in West Carney Field in Oklahoma. The Hunton formation covers 2.7 million acres in Oklahoma and in surrounding states of Texas, New Mexico and Arkansas and is one of the most prolific oil producing reservoirs in Oklahoma. The formation is geologically complex with a large number of fractures. Some of the unique characteristics of the field include decreasing GOR at the beginning of production, increase in GOR after shut-in and sustained oil rates over long periods of time. Fluid properties analysis of data obtained from laboratory tests has indicated that the reservoir fluid is volatile oil. Reservoir fluid model is generated from fluid properties data and is used in simulating the reservoir depletion process.
Production mechanism involved de-watering of the reservoir and production of oil and gas thereafter by solution gas drive. Since the reservoir fluid was observed to be volatile oil, a modified material balance method for depletion of volatile oil reservoirs was developed to calculate the initial in-place reserves and recovery factors.
A single well reservoir model was developed and compositional flow simulation was carried out using GEOQUEST E300 simulator. History matching methods were used to adjust the reservoir parameters to match the field production of both oil and gas wells. Most of the unique characteristics observed in the field could be reproduced using simulation. The model is also used to evaluate different enhanced recovery methods.
Controlling Water Production Using Gelled Polymer Systems
Authors: Willhite G. P. , Pancake R. E. 
Published: December 2007

Abstract
The Arbuckle reservoirs in Central Kansas are a major source of oil production. These reservoirs produce by natural water drive, yielding millions of barrels of fluid over 40 years with little decline in pressure from discovery pressures. Water oil ratios increased with time and ratios of 100:1 or higher are common when production becomes uneconomic. In the last three years, gelled polymer treatments have been used successfully to reduce water production in Arbuckle wells, prolonging the life of some wells and increasing oil recovery. Over 250 treatments have been applied. This paper describes results from a seven well program in which production wells were treated with chrome acetate-polyacrylamide gelant to reduce water production. Pressure data were obtained before the treatment to estimate reservoir permeability. Bottomhole pressure data obtained during the gel treatment provided insight into the behavior of gelant during placement. Finally, buildup data were obtained after gel treatment to determine the extent of permeability reduction to oil and water caused by the treatment. Production data following the treatments were analyzed to determine incremental oil production and correlate treatment to production response. Water production rates were reduced in every well and reductions were persistent over intervals ranging from 7-13 months. Incremental oil was produced in five of six wells treated in the program. The amount of incremental oil increased with volume of gelant injected in wells with open hole completions. Results of this test program suggest how to distinguish wells that are likely to take large treatments from those that can only be treated with small amounts of gelant. These results should improve treatment design and identify wells that are good candidates for successful treatment.
Integrated Reservoir Study of Shushufindi Field – Dynamic Modeling
Authors: Ohen Henry A. , Erian Adel , Ali Liaqat , Guzman Daniel , Guerrero Olga , Ochoa José , Valdivieso Luis 
Published: December 2007

Abstract
Shushufindi is the largest field in the Oriente Basin of Ecuador that was discovered by Texaco in 1970. It has produced about one billion barrels of oil over a period of 30 years. Early in the life of the field, peripheral water injection was implemented and was discontinued in 1999 based on the results of a previous reservoir simulation study carried out in late 90’s. Currently, the field is producing significant amount of water under very active water drive mechanism. The field consists of three main stacked reservoirs: Basal Tena, U and T and have produced from about 185 completions. This paper is focused on the reservoirs U and T. Historically, most of the wells in the field were produced commingled from these two reservoirs. This paper presents the results of an integrated reservoir study that was performed to optimize the field performance for effective reservoir management.
A 3D reservoir simulation model was constructed to optimize the performance of the field and to find opportunities to increase oil production. A successful history match achieved helped understanding the reservoir behavior and field performance. Since many wells produced commingled from the reservoirs U and T, dynamic fluid allocation was also performed by means of full-field history matching process. Distribution and location of remaining oil after accounting for the incremental oil recovery due to the workover wells helped delineating the locations of infill and step-out wells to increase production.
The results showed that reservoir pressure behavior was very erratic in both U and T reservoirs. However, the level of scatter was more pronounced in Reservoir U than in Reservoir T. Observed reservoir pressure trends seem to follow the channels observed from 2D seismic especially in reservoir U. However, local changes in the pressure trends could have been caused by the water injection. Some observations from the reservoir performance evaluation suggest that the erratic pressure behavior could also be attributed to the change in the formation compressibility due to fluid withdrawal and water injection.
The results also show that the effect of peripheral water injection was very limited and infill water injection could improve sweep efficiency of the reservoirs.
Measured Z-Factor of CO2–Dry Gas/Wet Gas/Gas Condensates for CO2 Storage in Depleted Gas Reservoirs
Authors: Adisoemarta P. S. , Frailey S. M. , Lawal A. S. 
Published: December 2007

Abstract
In support of the research project at the Center for Applied Petrophysical and Reservoir Studies in geologic storage of carbon dioxide in depleted gas reservoirs, the PVT laboratory at Texas Tech University performed compressibility factor (z-factor) measurements at various composition of CO2 with hydrocarbon (HC) gas mixture. For the sole purpose of the measured Z-factor data, three temperatures of 100°F, 160°F and 220°F and pressures ranges from 50 psia to 5000 psia are selected as representative of the depleted gas reservoirs (DGRs). In order to analyze the various phase behavior to be encountered in gas reservoirs (dry gas, wet gas and retrograde gas), the median gas compositions for dry, wet and retrograde gases are specified by gas type. The gas types are categorized by representative compositional analysis for the three types of gas reservoirs (dry gas, wet gas and retrograde gas). The measurements of z-factors for CO2-hydrocarbon mixtures in varying proportions and at the three specified temperatures for various pressures are performed on the median gas compositions of the type gases. The results of the z-factor measurements of CO2-hydrocarbon mixtures are used to interpret the expected phase behavior to be encountered in the geologic storage of CO2 in gas reservoirs. Also, the z-factor measurements of CO2-retrograde gas mixtures are used to quality the benefits of enhanced gas and condensate recovery in gas reservoirs.
Coiled Tubing Erosion During Hydraulic Fracturing Slurry Flow
Authors: Shah S. N. , Jain S. , Zhou Y. 
Published: December 2007

Abstract
The pumping of fracturing slurry through coiled and straight tubing can cause considerable wear of tubing and is an issue of industrial concern, both from safety and economic considerations. In hydraulic fracturing operations employing coiled tubing, the tubing wall is affected by non-uniform erosion for the section of the tubing spooled on the reel. The non-uniform wall erosion is caused by the centrifugal forces when pumping sand slurries at high rates. In spite of the large number of fracturing jobs performed in the industry today, research in this area of investigating and evaluating erosion has been limited.
This paper discusses the erosion phenomena and the mechanisms leading to the erosion process. The factors affecting erosion such as pump rate, slurry concentration, and fluid properties are investigated. Newtonian (water) and non-Newtonian (fracturing gel and slurry) fluids have been investigated. The results from the Computational Fluid Dynamics (CFD) simulations for the flow of these fluids in straight as well as coiled tubing are provided. The velocity profiles and sand concentration profiles for each case are presented which provide insight into the particle migration/segregation phenomenon associated with the erosion process. It is found that the fluid properties, flow velocity, and sand concentration all have major influence on the erosion process.
The future plans for the experimental study to understand the erosion in coiled tubing are also presented.
Finite Element Analysis of Coiled Tubing Forces
Authors: Newman Kenneth R 
Published: December 2007

Abstract
This paper will discuss a purpose written fully 3D Finite Element Analysis (FEA) model which analyzes the bending of pipe inside a wellbore. The yielding and residual curvature of CT can be included in this model. The model is also able to calculate the onset of buckling. This paper presents the equations and methodology used in the development of the model. Results from the model are compared with analytical solutions currently in use. Examples studies performed with the model are presented. .
Reverse Circulation With Coiled Tubing - Results of 1600+ Jobs
Authors: Charlie Michel , Rodney Stephens , David Smith , Walter Crow , King George E. 
Published: December 2007

Abstract
Reverse circulation has always been viewed with some level of suspicion and reverse circulation with coiled tubing has often been avoided at all costs. Yet, results of over 1600 CT operations involving reverse circulating in Alaska's oil fields, with just a handful of failures, has proven reverse circulation to be a reliable procedure for a specific range of solids removal that is extremely effective in removing sand fill from wells with very large tubulars and in high deviations. Results from North Sea, Colombia, California and the US GoM are also included. This paper presents the basics of reverse circulation designed specifically for coiled tubing; including necessary surface equipment, BHA nozzle design, pump requirements, fluid rates, and procedures to reduce the potential for problems. The procedures and job overviews contained here were contributed during an ICOTA panel discussion on reverse circulating, held September 18, 2003, in Houston, TX.