bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low Porosity Fractured Reservoir Characterization For Exploration and Horizontal Drilling
Authors: Sokolov E. , Makarytchev G. , Troitskaya E. , Tukhtaev R. 
Published: December 2007

Abstract
Yurubcheno-Takhomskaya oil and gas accumulation zone (YTZ) located in the western part of the Siberian platform is known as a really challenging exploration object. The main reservoirs are located in Riphean carbonates made up of single p.u. porosity dolomites. Prospective drilling of the territory demonstrated high heterogeneity of this formation. Prospective wells drilled to this formation tests results vary from 0 to more than 600 m3 oil per day.
The article describes efforts made on a new exploration approach elaboration based on an integral analysis of the structural, seismic and borehole data. First of all, this is seismic profiling on the regular orthogonal grid with the employment of modern seismic techniques and technologies, and also the study of the distribution of fractures in-situ (directly in the location of the deposition) with the integrated use of equipment and technology of formation micro-scanners and dipole sonic tools.
This new approach consists on high-potential zone localization controlled by the disintegrated levee-like stromatolithic constructions, which are more exposed to fractured formation due to high silification in the southern and northern slopes of the Madrinskiy and Irkineevo-Katangskiy rifts respectively. Besides, highly productive may turn out to be the highly fractured streaks and sections, controlled by the regional and zonal fault zones. Such localization of the highly productive sections within the huge oil-and-gas-bearing territory allows hoping for the realization of the opportunity of the recovery of reserves of the entire region by limited number of high flowrate wells with the natural recovery drive.
Formation Evaluation of Horizontal Water Injectors Drilled in Thick Carbonate Reservoirs: Behind-Casing-Analysis and LWD Resistivity Modeling
Authors: Ma S. M. , Al-Hajari A. A , Butt P. , Crary S. 
Published: December 2007

ABSTRACT
Formation evaluation (FE) of horizontal injectors drilled in water swept reservoirs involves different physical understanding of log responses to fluid flow and distribution than that FE of oil producers drilled in dry oil intervals. In reservoirs swept with water, effects of rock electrical anisotropy on logging-while-drilling (LWD) apparent resistivity measurements (attenuation and phase shift) could be significant. These effects need to be considered in resistivity log interpretation. In this study, LWD resistivity modeling work was conducted to study relationships between true formation resistivity and LWD tool responses. In situations where the time-consuming resistivity modeling/inversion is not available, LWD apparent attenuation is found to be more representative to true formation resistivity than the apparent phase shift resistivity, thus can be used in formation water saturation estimation.
An alternative measurement of formation fluid saturation is by pulse neutron (PN) after well completion. New technologies have been developed to characterize formation saturation through casing, i.e., behind-casing-analysis (BCA) which includes PN and casedhole resistivity. Logging long horizontal intervals of BCA services is different from logging vertical wells. First of all, the issue of vertical resolution in horizontal wells is not as critical. Secondly, the gravity effect on the tool orientation is different. Data quality could also be different when logging long intervals of the casedhole resistivity because the tool requires physical contact between the measurement pads and the casing. In this paper, all these issues are summarized. The BCA logs are integrated with results of the LWD modeling and production data while underbalanced drilling to provide more accurate formation evaluation.
Optimized Tubing String Design Modeling for Improved Recovery
Authors: Poe B. D. 
Published: December 2007

Abstract
This paper presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells that produce free liquids in conjunction with the gas. Particularly important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required to continuously transport and unload liquids from the well. Subcritical velocities are often encountered in low productivity gas wells that produce liquids, whether the wellbore liquids are produced directly from the formation and/or condensed from the gas in the wellbore. The produced liquids considered in the analysis can be water and/or liquid hydrocarbons.
This paper presents an optimization technique for determining the most efficient production tubing string setting depth design that will keep the wellbore continuously unloaded of produced liquids, yet result in the maximum gas recovery possible under those conditions. The optimization can be performed for a single completion operation during the productive life of the well, or for a series of periodic well interventions during the productive life of the well for which the tubing string setting depths are selected.
The wellbore liquid-loading mechanism in a sub-critical velocity production system has been considered in the analysis using a mechanistic wellbore outflow model. A commingled reservoir inflow performance model was utilized in the analysis to evaluate the fluid inflow of multilayer gas reservoirs that may produce liquids in conjunction with the gas.
Formulas for Rupture, Necking, and Wrinkling of OCTG Under Combined Loads
Authors: Klever F. J. 
Published: December 2007

Abstract
Advanced well design methods based on risk assessment of actual failure mechanisms require accurate formulas for burst, collapse, yield and fracture. Moreover, these strength formulas should be generalized to account for the combined internal pressure, external pressure and axial load that well tubulars experience.
This paper describes the development of a set of formulas for burst strength, i.e. the failure envelope and the design limit for OCTG under internal over-pressure and any axial tension or axial compression. Phenomena covered are ductile rupture, pipe necking and local pipe wall wrinkling, thus spanning the first and second quadrant in the effective axial load – pressure differential load space.
It is based on a large strain, elastic-plastic, &lt; 3D &gt; formulation of pipe equilibrium, deformation and buckling that has been solved analytically in closed form for the situation of combined loads. The formulas describe features such as a maximum internal pressure load (rupture), a maximum axial tension load (necking) and local buckling of a pipe under axial compression (wrinkling).
Approximate burst strength formulas are presented that together span the entire axial load range and closely match the more complex, exact model predictions.
The joint API/ISO SC5 Work Group 2B tasked with modernizing the API 5C3 property equations has incorporated the burst strength formulas presented in this paper into the new ISO TR 10400 standard1.
Acid Fracturing or Proppant Fracturing in Carbonate Formation? A Rock Mechanic's View
Authors: Abass H. H. , Al-Mulhem A. A. , Alqam M. S. , Mirajuddin K. R. 
Published: December 2007

Abstract
Acid fracturing is performed to improve well productivity in acid-soluble formations such as limestone, dolomite, and chalk. Hydrochloric acid is generally used to create an etched fracture, which is the main mechanism for maintaining the fracture open during the life of a well. Proppant fracturing is an alternative option that has been applied in carbonate formations. In certain areas, proppant fracturing has been used as a standard stimulation method for carbonate formations. There is no quantitative method to provide an answer of whether acid fracturing or proppant fracturing is an appropriate stimulation method for a given carbonate formation.
In proppant fracturing, proppant is used to sustain the effect of the minimum horizontal stress from closing the fracture. In acid fracturing the etched, non-smooth, surface with sufficient roughness should leave open channels upon closing. The effect of elastic, plastic, and creeping deformations in acid fracturing and the proppant crushing and embedment in proppant facturing, on reducing fracture permeability is investigated. The viscous effect, creeping, is a slow displacement that incurred over a long period of time. The creeping effect on fracture closure following an acid fracturing treatment is demonstrated in this paper.
Laboratory experiments have been performed to simulate acid and proppant fracturing treatments. The effect of elastic, plastic and viscoelastic rock behavior on fracture conductivity was studied for acid and proppant fracturing treatments, using full core samples. Comparison of acid vs. proppant fracturing conductivity in carbonate formation is also presented.
A New Hydraulic Fracturing Package Fit for Arctic Conditions Improves Operational Efficiency and Fracture Conductivity and Enhances Production in Western Siberia
Authors: Kirilov V. , Yamilov R. , Lyubin G. , Dessinges M-N. , Parris M. , El Kholy I. , Leugemors E. , Ayala S. , Pessin J-L. , Fu D. , Sock D. , Maniere J. , Butula K. , Mullen K. 
Published: December 2007

Abstract
The extreme weather, the poor road conditions, the use of a wide variety of local river and produced waters, and the time-consuming batch mixing operations of tons of gel prior to the operation make each fracturing job in Siberia a real challenge. In a market where production needs are growing, efficiency and streamlined operations are required to enable a higher utilization rate and maintain execution quality.
This paper introduces a new system where engineered polymer-based fracturing fluid and mixing equipment were integrated. While the conventional fracturing systems employ either batch mixing of gel for hours prior to the operation, or continuous mixing using polymer slurries suspended in hydrocarbon, the solution introduces mixing on-the-fly of all the streams, including the dry polymer, the crosslinker, and the activator streams. This significantly reduces the duration of each treatment. With the utilization of high yielding polymer, the new technology allows a reduction in polymer loading close to 20%, which translates to an increase in proppant pack conductivity of up to 10%, and thus an increase in productivity. The new technology introduces blends, allowing increased simplicity and improved reliability. The enhanced utilization of dry chemicals in an environment of sub-freezing temperatures also contributes to the operational simplicity. The system incorporates a robust chemistry with reduced sensitivity to additive concentrations and improved compatibility with local waters. The system has a broad application temperature range from 37°C to 149°C.
As of today, 143 treatments have been successfully performed in the Priobskoe region of western Siberia with the integrated solution using various fields mixing waters. The duration of treatments has been reduced on average by 8 h, while 100% of the proppant was placed in 88% of the cases. The new fluid system has further allowed a decrease in polymer loading of 17% during the treatments.
The Potential of Multiple Fractured Horizontal Wells in Layered Reservoirs
Authors: Butter Machiel , East Loyd , Kuvshinov Igor 
Published: December 2007

Abstract
Many western Siberia oil fields are being developed/exploited with hydraulically fractured S-shaped wells (vertical through the pay section). Horizontal wells are also used; however, in many of the fields these wells are outperformed by vertical, fractured (VF) wells. The reasons for this often are poor vertical permeability and sub-optimal drilling and completions practices.
To better quantify the potential of an undeveloped area of a western Siberian field, five different well types were evaluated: vertical, vertical-fractured, slanted (85°, crossing multiple layers), horizontal (with a single layer), and multiple-fracture horizontal (MFH) wells. These well types were evaluated using a reservoir simulation model of a sector of the field. The results of this analysis demonstrated that the MFH well completions can outperform the other well types and that they can have a positive impact on the economics of the field development.
With traditional fracturing and completion techniques, where packers or bridge plugs are used to provide zonal isolation, fracturing horizontal wells is a complex operation with substantial risks and is not always economical. New hydrajet-assisted fracturing (HAF) techniques can eliminate many of the problems and reduce the risks. Recent developments in this technology make it simpler to perform the same type of aggressive frac jobs as currently performed in vertical wells, with large proppant volumes and large proppant sizes (12/18-mesh), at multiple selected locations along a lateral wellbore.
To realize the full potential of this type of well, traditional thinking, regulatory barriers, and equipment limitations need to be overcome. This process has started, and some operators are currently planning trial MFH wells to demonstrate their potential.
This paper discusses the potential demonstrated by the study and recent technology developments that will allow the easier placement of multiple fracs in horizontal wellbores. It also highlights the practical aspects that need to be addressed for operators to fully capture the potential.
A Generalized Material Balance Equation for Coalbed Methane Reservoirs
Authors: Ahmed T. , Centilmen A. , Roux B. 
Published: December 2007

Abstract
The objective of this paper is to present three contributions regarding the mathematical development of material-balance-based methods for analyzing unconventional gas reservoirs, particularly coal bed methane ("CBM") reservoirs. These three contributions are:
Contribution 1: A generalized material balance equation ("MBE") that accounts for and incorporates the Langmuir isotherm, initial free gas, water expansion, and formation compaction. This particular form of material balancing can be used to estimate the original gas-in-place and, unlike other methods, does not require an iterative process to solve the equations involved.
Contribution 2: Prudent CBM reservoir management and optimization requires knowledge of reservoir pressure. An iterative method has been developed to predict reservoir pressure throughout the producing life of the reservoir using only initial reservoir pressure, Langmuir isotherm, and cumulative gas production. Use of the proposed method has the potential to significantly reduce operating costs by minimizing the number of pressure surveys.
Contribution 3: A contribution designed to provide an efficient iterative scheme that incorporates the gas-water relative permeability data to predict future performance of the CBM reservoir.
The paper documents the practical applications of the proposed MBE and verifies its accuracy through comparison with results of numerical simulation on several field examples.
The proposed MBE can provide an independent source of validation for numerical simulators and is applicable to any coal which behaves according to the Langmuir isotherm equation. The Method can accurately predict the future production and pressure performance and, hence, it has the potential to significantly reduce operating costs by minimizing the number of pressure surveys required.
Enhancements in PDC Bit Design and Drilling Optimization Tackle Hard Conglomerate Rock Drilling in Northern Mexico
Authors: Rodriguez Carlos Solano , Montejo Carlos , Yam Ricardo , Bustos Oswaldo , Luis Sanchez Jose , Romero Jorge , Rodriguez John 
Published: December 2007

Abstract
This paper discusses the successful application of polycrystalline diamond compact (PDC) bits in drilling a hard conglomerate formation with confined compressive strengths in the range of 20,000 to 40,000 psi. Over 30% savings in drilling cost was achieved through improved penetration rate, extended bit life and reduced bit trips.
Advances in bit design and cutter technology are allowing PDC bits to be used repeatedly in this hard conglomerate interval in northern Mexico's Burgos basin. Previously the exclusive domain of IADC 417 to 537 insert rock bits, the heterogeneous formation contains chert nodules that are too hard for conventional PDC bits, which are subject to cutting structure damage that reduces the rate of penetration (ROP).
A conventional bit program for this formation used a PDC bit to reach the top of the Conglomerada Norma interval, then changed to an insert bit to drill to the base of the conglomerate. A final trip picked up a PDC bit to reach interval TD. This formation is quite common throughout the basin and is found at various depths and thickness in the Cuitlahuac, Torrecillas, Comitas, Fundador and Sigma fields.
Case histories will illustrate successful application of advanced PDC bit designs in conjunction with optimized drilling parameters and bottomhole assemblies, as well as cost savings achieved throughout the course of this drilling campaign. This enhanced technology in conjunction with effective teamwork involving the operator, drilling contractor and bit supplier established field records while reducing drilling expenditures.
Modeling the Effect of Viscosity Ratio on Spontaneous Imbibition
Authors: Fischer H. , Wo S. , Morrow N. R. 
Published: December 2007

Abstract
Spontaneous imbibition data for Berea sandstone cores, that are very strongly wetted by the aqueous phase and initially 100% saturated with mineral oil, are reported for linear, radial, and all-faces-open boundary conditions. Oil viscosities were 4, 63 and 173 cP and aqueous phase viscosities ranged from 1 to 495 cP. Oil/aqueous phase viscosity ratios were varied by over four orders of magnitude (0.01 to 173.1). Near-linear relationships, with slopes close to one half, between the frontal position and imbibition time on a log-log scale were obtained for both linear and radial counter-current flow. Behavior is consistent with near piston-like displacement by the imbibing aqueous phase. The results are analyzed by a new mathematical model that accounts for counter-current spontaneous imbibition with symmetrical flow patterns. The model assumes that saturation and permeabilities to counter-flowing phases behind the front are constant and that any effect of local change in interfacial curvature with distance is negligible. The results from the model are used to extend scaling to include the measured effect of viscosity ratio for linear and radial flow. For the all-faces-open boundary condition, commonly used in core analysis studies, oil recovery vs. imbibition time is estimated by a combination of spherical and radial flow. Consistently close agreement was obtained between experiments and behavior predicted by the model.
Statistical Study of the Crush Resistance Measurement for Ceramic Proppants
Authors: Stephens W. T. , Schubarth S. K. , Rivera D. I. , Snyder E. M. , Herndon D. C. 
Published: December 2007

Abstract
Crush resistance and size distribution are two measurements to select a proppant. While standard sieve analysis provides a good quantitative value for crush resistance, detailed size measurements can provide more understanding of proppant failure and the alteration of size distribution under load. The variance in proppant crush resistance is often larger than the typically reported accuracy of ±0.1%. In many cases, specimen handling and material retention upon sieves makes a real contribution towards measurement error.
This paper documents the variation in crush resistance measurements for proppants of similar size and size distribution at constant stress. Optical measurement of the size distribution can reveal more information about proppant failure under load. The paper discusses the sensitivity of the measurement with respect to manual versus automatic load application, loading rate, cell size, and specimen mass. The accuracy and precision of the test, along with the minimum sample size, are reported. The relationship between size distribution and crush resistance for different proppant materials is also presented.
The results of this paper address expanding the technical evaluation of proppants using new tools and analysis methods to provide a greater understanding of the crush resistance measurement. Operators will be able to select an appropriate proppant for their application with a practical understanding of measurement variation.
Seismically Based Integrated Reservoir Modelling, Lunskoye Field, Offshore Sakhalin, Russian Federation
Authors: Ross Liz , King Kevin , Bodewitz Gerard , van Hasselt Hajo , Stone Greg , Twigt Wim , Swinkels Wim , James Andrew , Addis Tony , Parsons Chris , Meij Robert , Bell Sarah , Trofimov Alexei , Jackson Patrick , Cholovsky Valery , Lamers Edwin , Crouch Syrie 
Published: December 2007

Abstract
The Lunskoye Field is a centrepiece of the Sakhalin II development, one of Shell's most significant current projects. Demand for LNG in the nearby Asia-Pacific market and availability of a large (18.2 Tcf GIIP) gas resource underpins the investment decision in a challenging offshore environment.
Robust suites of seismically-constrained integrated reservoir models were generated to evaluate short-, medium- and long-term subsurface uncertainties. Previous quantitative reservoir mModelling efforts were hampered by the existence of shallow gas over the crest of the structure, which masked the seismic response in the crestal area of the reservoir. This impacted the evaluation of structure and reservoir properties from seismic. To address this, a new 3D-survey was acquired in 2003, in an east-west direction, to undershoot the shallow gas deposits. The Pre-Stack Time Migration and Pre-Stack Depth Migration seismic results show the reservoir image is greatly improved, and there is improved confidence in the seismic signal that allows it to be used for the definition of rock property distribution.
In parallel to the seismic interpretation, a detailed evaluation of velocities, core, and well-log information was undertaken to provide input into an in-house probabilistic model-based seismic inversion (1). This fundamental work was used to: construct an integrated and fully consistent structural and stratigraphic hierarchical framework, in the lateral and vertical domain;update the view of the depositional setting, taking into account variations in provenance and relative sea-level;define the petrophysical parameters for the rock property model, which underpins the inversion.
The results of the model-based inversion formed the basis of the detailed static models and analysis of key subsurface uncertainties. Results of the improved property models were upscaled and fed into the well inflow models and dynamic models to improve productivity estimates, long-term reservoir performance prediction and to support development planning and reservoir management.
This paper summarises all of the refinements undertaken as part of the new model building, including the improvement in the seismic data, the insight into the stratigraphic changes, the hierarchical framework, the rock property model, the probabilistic inversion, the well inflow modelling, and the dynamic simulation.