bluuebunny/crossref_metadata_2025_split huggingface dataset:
Vug Characterization and Pore Volume Compressibility for Numerical Simulation of Vuggy and Fractured Carbonate Reservoirs
Authors: Iwere F. O. , Moreno J. E. , Apaydin O. G. , Ventura R. León , Garcia J. L. 
Published: December 2007

Abstract
Three porosity types, matrix, vugs and fractures, are usually present in naturally fractured, vuggy carbonate reservoirs. The vugs are generally considered connected either to the matrix or to the fractures in numerical simulation. One of the challenges of modeling these reservoirs is the partitioning of the porosities into two components since dual porosity reservoir simulators can only handle two rock components, namely matrix system and fracture system. The goal of this study is to characterize the vugs in these systems, and to determine the pore volume compressibility for the simulation of vuggy, naturally fractured reservoirs.
Sequential laboratory experiments were designed and conducted to determine the amount of secondary porosity in the core samples. A combination of capillary pressure (centrifuge and mercury injection experiments) and NMR experiments was used to determine the vug or secondary porosity of the samples from pore size and T2 (relaxation time) distributions. The results were compared and reconciled with those from porosity logs and image logs. Pore volume compressibility tests and compaction tests were used to determine the compressibility of each sample. The compaction and pore volume compressibility tests were evaluated at different net stresses to determine the influence of vuggy porosity in the samples.
The composite (sample) compressibility versus porosity plots showed that pore volume compressibility increases as secondary porosity increases. This dependence, which is strong at low net stresses, gradually disappears as the reservoir pressure decreases or the net stress increases. This implies that the effects of secondary porosity on pore volume compressibility of the total system are minimal at low reservoir pressures. Based on these results, pore volume compressibility was generated for various values of effective and secondary porosity and served as input data to the numerical flow models. The development of the vug porosity, pore volume compressibility and the construction of the simulation flow model are described in this paper.
The Hybrid Drilling Unit: An Overview of an Integrated Composite Coiled Tubing and Hydraulic Workover Drilling System
Authors: Coats E. Alan , Farabee Mark 
Published: December 2007

Abstract
Since the decline of the cable-tool rig, well construction operations have been performed exclusively with some variation of steel tubulars. Recently a drilling system that combines composite coiled-tubing technology and hydraulic workover technology has been introduced. This paper examines the benefits of the combined system.
A newly developed composite coiled-tubing drillstring with embedded conductors allows this revolutionary drilling system to achieve uninterrupted, real-time, two-way communication with the downhole tools. This allowed a step-change improvement in the knowledge of dynamic wellbore conditions and in the overall control of downhole drilling assemblies and systems. Subsequently, new procedures were developed to assimilate and use this increased functionality. These procedures include both geosteering and real-time system diagnostics from remote locations.
Incorporating a hydraulic workover (HWO) jacking system as an integral part of the unit expanded the operating envelope and functionality of the entire system. The HWO unit allows for jointed pipe drilling in both underbalanced and overbalanced situations. The HWO unit also serves as a platform to perform jointed pipe completions. When combined with the composite coiled-tubing drilling unit, the resultant "hybrid" drilling system greatly expands the options now available for developing hydrocarbon reserves.
A Triple-Mechanism Fractal Model with Hydraulic Dispersion for Gas Permeation in Tight Reservoirs
Authors: Civan Faruk 
Published: December 2007

Abstract
This paper presents a triple-mechanism-fractal model including the hydraulic dispersion effect to more accurately describe the gas flow in tight gas reservoirs than the frequently used Darcy law. By comparison to Darcy's law, this paper demonstrates that the improved formulation presented in this paper is more adequate.
A Darcy-like equation using an apparent permeability is derived by considering the gas transport by three mechanisms, which may occur in tight pore space under different Knudsen number criteria. This equation incorporates the Knudsen, slip, and viscous flow mechanisms into the description of gas flow, each prevailing under different conditions. The characteristics of porous media are represented by fractal equations. The equation of continuity includes the effect of hydraulic dispersion, which has been omitted in the usual reservoir analysis. These equations are solved analytically for one-dimensional, horizontal, and steady flow in laboratory core tests and radial flow in the near-well bore region.
The present analysis indicates that Darcy's law fails to describe the flow of gas in tight formations under the Knudsen and slip flow conditions, because Darcy's law was designed to represent the viscous flow by analogy to liquid flow. Hence, the flow of gases through porous medium should be treated differently than liquids. In addition, the walls of tight pores in porous media interfere with the mean-free motion of gas molecules and cause a strong deviation from Darcy's law. Further, the porous media macroscopic mass conservation equation should include a term for transport by hydraulic dispersion due to mixing and compressibility effects. Therefore, the conventional well test interpretation methods require a correction when the flow occurs under the Knudsen and slip flow conditions. This confirms the significance of the model presented in this paper.
The triple-mechanism with hydraulic dispersion model presented in this paper can be used for accurate and convenient means of describing gas flow in tight-geological porous media undergoing various flow regimes.
Novel Application of Ecological System Drilling Fluid Accomplishes Significant Advances in the Hole Stability Problems
Authors: Héctor Mandujano Santiago , Ramirez Ricardo Lara , Heliodoro Perez Palacios 
Published: December 2007

Summary
In deep well drilling operations, borehole stability causes severe problems that requires excessive rig time to solve them. The not productive times are about the thirty percent of the total drilling time. The wells located at the south region of Mexico are characterized by being of high pressure and high temperature with surface and intermediate length zones (3500 meters approximately) formed by sands and clays. The incidence of this problem is explained by the rock-fluid interaction "mud - rock". An immediate solution has been the use of oil based muds; however, sandy layers present another problems. An additional problem is the strong ecological restrictions due to Well's geographical location. From three years ago, Pemex has studied the phenomenon through a project called "Improvement in the compatibility drilling fluid-formation" obtaining significative advances.
According to the importance of having a water based fluid that faces conditions, it was necessary to develop a drilling fluid system that could be able to maintain, by an extended period of time, the stability in the clays. From vast laboratory studies to core samples, the Luna field was selected to use a polymeric potassium-silicate drilling fluid. As a result, it was obtained a drilling fluid that maintained an excellent borehole stability during 70 days. This was the best result compared with other systems used in the area. It is of equal importance the fact that the fluid is environmentally friendly.
Strategic Sustainability Integration: The Next Step in the Journey
Authors: Wilcoxon Bruce R. , Cramer David F. 
Published: December 2007

Abstract
Conoco's journey towards sustainability began in earnest about 2 years ago as an "incremental" effort to bring increased awareness of environmental and community responsibility to existing operations. Since then however, the company has evolved to a much richer understanding of sustainable development and its potential. Sustainable development is now considered a strategic framework for long-term business success with the potential to shape the company's direction and is the foundation for Conoco's vision of achieving sustainable business growth. Committing to financial excellence, environmental stewardship and broad, ongoing contributions to social development earns Conoco its license to operate and allows us to embrace new, value creating opportunities by leveraging our capabilities to bring sustainable solutions to our customers and stakeholders. In short, our commitment to sustainable development is seen as a fundamental prerequisite for Conoco's survival and success in the new century.
Like many companies that have embraced the concept of sustainable development, Conoco is now embarking on the challenge of translating that vision of economic, environmental and social sustainability into the reality of tangible value creation and sustainable growth. Strategic sustainability integration represents a shift in mindset away from traditional regulatory compliance, risk abatement, and cost control into the realm of opportunity identification. The purpose of this paper is to discuss Conoco's experience with strategic sustainability integration in its operations from around the world. Examples will describe community development efforts in Nigeria, the positive environmental impact of a natural gas project in Syria, as well as an integrated approach to extra-heavy oil development the environmentally sensitive Orinoco Oil Belt of Venezuela. These and other efforts represent the beginning of Conoco's journey towards strategic sustainability and total economic, social, and environmental value creation.
Causes of Injectivity Problems During Fractured Water Disposal and Their Remediation
Authors: van den Hoek P. J. , Khatib Z. I. , Siemers G. J. 
Published: December 2007

Abstract
For many years, all the untreated production water from the Groningen gas field in The Netherlands had been injected into a dedicated water disposal well without problems. Recently, however, the injectivity of this well reduced significantly as a result of downhole blockages. Various remedial injection well clean ups and acidisations were executed without much long-lasting success. Early 2001, a dedicated study was conducted to identify the causes of the problems and come up with remedial actions. In particular, the question was whether the well plugging was due to the the low quality of the injection water, which would imply building dedicated water treatment faclities in order to remediate the problem, or whether the blockages were due to some other mechanism.
By carrying out a thorough analysis of all the injection data over the years, and combining this analysis with water injection computer simulations, it was concluded that the injectivity problems had nothing to do with the low injection water quality, but were the result of sand production during shut-ins. This result appeared surprising at first sight as the disposal water is injected into a fairly competent sandstone. It led to a set of recommendations for an improved way of operating the disposal well. The recommendations have been followed up, as a result of which the well has been in operation trouble-free over the last six months.
Coreflood Studies to Examine Potential Application of Novel Scale Inhibitor Products to Minimise Intervention During Field Life Cycle
Authors: Jordan M. M. , Collins I. R. , Gyani A. , Graham G. M. 
Published: December 2007

Abstract
With the development of more and more subsea fields, the challenge for scale inhibitor squeeze treatments is to reduce intervention frequency by extending squeeze treatment lifetime whilst concomitantly reducing any potential damage in both low water cut and higher water cut wells. This paper discusses the technical problems and examines new technologies for treatment of such production wells through their life cycle.
Scale control technology available to control scale formation within the reservoir and near-wellbore area of production wells will be outlined with a focus on the current developing technology to control scale within low water cut wells. Moreover, it is shown that the new technical area of emulsion scale inhibitor delivery systems, originally designed to control scale within low water cut wells, has application in both low and high water cut wells
This study assists in developing an understanding of the mechanism of interaction of emulsion-based products; in particular the impact of the level of water saturation within the core system. In addition, it demonstrates that the emulsion particles are retained in the core matrix during both crude and brine flowback. This paper indicates that the emulsion product offers the potential for extremely long squeeze lifetimes with minimal damage in oil production wells with rising water cut. It also demonstrates how different technologies have their own place in the life cycle of a production well.
A Rigorous Formation Damage Skin Factor and Reservoir Inflow Model for a Horizontal Well
Authors: Furui K. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
In this paper, we present a new analytical model for formation damage skin factor and the resulting reservoir inflow that includes the effect of reservoir anisotropy and damage heterogeneity. The shape of the damaged region perpendicular to the wellbore is based on the pressure equation for an anisotropic medium, and is thus circular near the well and elliptical far from the well. This assumption gives an appropriate skin factor even for a small penetration of damage. The new model can be used for any distribution of damage along the well. The new skin factor model can be easily incorporated into any existing model of reservoir inflow for a horizontal well.
We also present a new reservoir inflow equation for a damaged parallelepiped-shape reservoir drained by a horizontal well. This equation shows that the ratio of the reservoir thickness to the drainage length perpendicular to the well is a very important factor for determining the influence of formation damage on horizontal well productivity because the linear flow geometry becomes dominant for a thin reservoir. The larger the ratio of thickness to drainage length perpendicular to the well axis, the larger the influence of nearwell formation damage on well productivity.
In examples presented in the paper, a truncated elliptical cone of damage with a larger penetration near the vertical section of the well (at the heel) is presumed to compare our model with an existing horizontal well damage skin factor model. The comparisons show that, for an anisotropic reservoir with shallow-penetrating formation damage, our model avoids the negative skin result calculated by the previous model and predicts higher skin factor than the existing model. For deep damage, the new model predicts lower skin factor than the previous model.
The impact of formation damage on the overall production is also shown in examples. In general, the effect of near well formation damage for a horizontal well completion is relatively small compared with vertical wells. However, if the reservoir thickness is large, radial flow becomes dominant and the impact of formation damage on a horizontal well is more significant, more like that of a vertical well. Our model gives a simple, analytical expression for determining this effect.
Residual Gas Saturation to Aquifer Influx: A Calculation Method for 3-D Computer Reservoir Model Construction
Authors: Holtz M. H. 
Published: December 2007

Abstract
Residual gas saturation controls the volume of gas trapped in that portion of the reservoir that has experienced water encroachment. As water moves into a rock volume filled with gas, the water displacement of the gas is incomplete. The water fills pores and pore throats, causing capillary pressure and relative permeability effects to stop the flow of gas and allow only water to pass through the rock volume. This stoppage results in gas being trapped behind the encroaching waterfront as residual gas. The volume and location of the residual gas are controlled by the distribution of the petrophysical properties.
A method based on interrelationships between petrophysical properties is used to create a model for calculating maximum residual gas saturation (Sgrm). The model is developed as a function of porosity, permeability, capillary pressure, and initial water saturation. The input to the model and its results compare favorably with actual field data where aquifer encroachment is verified from well production history.
Methane Number Control of Associated Gas from Oil Production
Authors: Ohlrogge K. , Zettlitzer M. , Hartmann U. , Boße D. , Wind J. , Brinkmann T. 
Published: December 2007

Abstract
The paper deals with filed experiments to control the methane number of associated gas, which was used as fuel gas to operate a gas engine. The methane number has a strong impact on the anti-knocking behavior of the fuel gas. A membrane separator equipped with elastomeric membranes separates the higher hydrocarbons from the associated gas. In dependence of the gas source and the ambient temperature the methane number of the gas fluctuates. A methane number higher than 50 was required to ensure a smooth operation of the Otto carburetor engine. Operating experiences with the pilot unit will be discussed as well as membrane data and design criteria for a commercial plant.
Material Balance as a Horizontal Line for a Gas-Condensate Reservoir
Authors: Hsieh Frank S. , Vega Cecilia , Vega Lucy 
Published: December 2007

Abstract
Straight-line material-balance plots are commonly applied to analyze reservoir performance and estimate the OHIP (original-hydrocarbon-in-place). Depending on the type of the straight-line plot is applied the OHIP may be found either from the slope or the intercept of the straight line. In the case of a gas-condensate reservoir, the compositional effect and the overpressure effect must be formulated into a general material-balance equation to obtain a valid straight-line plot. For obtaining a correct OHIP a line must be both linear and having the correct slope or intercept when straight-line material-balance plots are used. Unfortunately, a quality material-balance evaluation for a gas-condensate reservoir is difficult to achieve using straight-line material-balance plots because the additional data required for calculating the compositional effect and the overpressure effect are difficult to obtain. This paper illustrates that the compositional effect and the overpressure effect can be ignored if the results obtained based on a general material-balance equation are plotted as a horizontal line. In horizontal line material-balance plot no slope or intercept is used as the condition for determining the OHIP because only a correct OHIP can give a horizontally linear material-balance plot, the only condition to meet. Horizontal-line material-balance plots simplify the evaluation procedure and improve the quality of material-balance valuations.
The Interplay of Forces and Their Strength on Fluid Flow in Gas Condensate Reservoirs
Authors: Ursin Jann-Rune 
Published: December 2007

Abstract
Production from gas condensate reservoirs is characterized by condensation of gas and liquid dropout, first in the near wellbore volume, then as a region dynamically developing into the reservoir. The effects of liquid condensation are reduced productivity and loss of production. Successful forecast of well productivity from gas condensate reservoirs depends on proper understanding of the various forces acting on fluid flow in time and space. Production form these reservoirs is thus indirectly related to the interplay of fundamental forces, such as; inertial, viscosity, capillary and gravity, and their relative strengths, demonstrated through various dimensionless numbers.
Dimensionless numbers are defined and calculated for all pressure and space coordinates in a test reservoir, thus defining various dynamical regions where certain forces are dominating over others. Identification of these regions in a reservoir facilitates use of pseudo permeability functions, which again should be correlated to interplay of forces.
Material balance -, reservoir fluid flow - and wellbore flow calculations are performed on a cylindrical reservoir model. The ratios between fundamental forces are calculated and dimensionless numbers are defined. The interplay of forces, demonstrated by these numbers, are calculated as function of radial dimension and reservoir pressure. Comparisons of the different dimensionless numbers are performed and gas permeability is evaluated in the test case.
On the Characterization of Carbonate Reservoirs Using Low Field NMR Tools
Authors: Mai A. , Kantzas A. 
Published: December 2007

Abstract
Alberta contains significant deposits of oil and gas in carbonate formations. Carbonates tend to have fairly tight matrix structures, resulting in low primary porosity and permeability. As a result, laboratory characterization of carbonate properties is a slow and tedious process. Low field NMR is an emerging technology shows great promise in rock characterization. In a single NMR experiment, rock properties like porosity, permeability and Swi can in theory be measured.
Experiments were performed on approximately 80 core plugs from six carbonate formations. Porosity measurements were performed through gas expansion and brine saturation (Archimedes’ principle). Air permeabilities were also measured. Cores were also saturated with brine and spun to irreducible water saturation. NMR measurements were taken at both saturation stages (Sw = 1.0 and Sw = Swi). NMR data were interpreted using the conventional core analysis results as guides. Observations were made regarding NMR trends and corresponding rock properties.
Preliminary analysis of the data shows that NMR can successfully predict the content and distribution of the fluids in the porous media. Also, the NMR spectra of carbonate samples seem to suggest that NMR can be used as a tool for classifying cores into different pore systems.
Using T2cutoff values as a tool, the cores can be divided into groups. Group 1 has T2cutoff &lt; 80 ms, while group 2 has T2cutoff in the range of 80 to 200 ms and group 3 has T2cutoff values &gt; 200 ms. Group 1 cores generally have higher porosity values than groups 2 and 3. Group 1 also has low values of T2gm, compared to the other two groups. Air permeability was compared to the geometric means and T2gm_cutoff values of the three groups and some general trends were observed, but more analysis is required before these trends can be quantified.