bluuebunny/crossref_metadata_2025_split huggingface dataset:
Asphaltene Deposition During CO2 Flooding: A Laboratory Assessment
Authors: Srivastava Raj K. , Huang Sam S. 
Published: December 2007

Abstract
In a CO2 miscible displacement process, the injected CO2 solvent can induce flocculation and deposition of asphaltenes and other heavy organic particles. This can cause numerous production problems with a detrimental effect on oil recovery. Therefore, it is important to understand the behavior of this organic matter under reservoir operating conditions. This paper presents results of dynamic and static precipitation tests conducted at reservoir temperature and pressure conditions to investigate the likelihood of asphaltene deposition problems in the Weyburn reservoir (in southeast Saskatchewan). A laboratory study using a high-pressure PVT cell was undertaken to determine the effect on asphaltene flocculation/precipitation of operating pressure, CO2 concentration, gas contaminants in CO2, and presence of formation brine for three different oil samples collected from the reservoir. The extent of asphaltene deposition was also assessed through coreflood experiments using preserved and restored reservoir core material collected from different reservoir zones of increasing permeability (Marly, Vuggy, and high-grain-size Vuggy) and through a suitably designed X-ray CAT-scanning visualization experiment.
Static tests indicated the most important factor on which the asphaltene precipitation depended was the CO2 concentration. For oils belonging to the same pool, the increase in asphaltene precipitation with solvent concentration was proportional to the initial asphaltene contents of the oil. Coreflood experiments showed a considerable increase in asphaltene deposition in the core matrix following CO2 injection. Pore topography of the core matrix played an important role in the extent of CO2-induced asphaltene deposition. The deposition appeared to be higher in a high-grain-size Vuggy matrix than in the normal Vuggy matrix, and lowest in the Marly matrix. X-ray CAT-scanning tests depicted localized areas of asphaltene deposition along the length of the core, with significant deposition suspected to be occurring near the inlet of the core. The CAT-scan tests also identified sites of suspected formation damage to the core matrix associated with CO2 injection.
Diffusion Of Gas In Oil Based Drilling Fluids
Authors: Bodwadkar S. V. , Chenevert M. E. 
Published: December 2007

Abstract
Background gas has been observed in oil based drilling fluids in contact with gas bearing formations. It has been postulated that such background gas is caused by diffusion. The objective of this study was to quantify the transport of gas by diffusion. The effect of filtrate flow into the formation (against the gas transport) has been evaluated.
The diffusion coefficients of the filter cakes were determined in the laboratory at various temperatures and pressures. The significance of diffusion was mostly decided by the rate of filtration. The flux of gas by diffusion drops sharply at some threshold value of pressure differential in the wellbore, irrespective of the temperature.
Cautious Utilization of Formation Micro-Imaging Logs
Authors: Fitzsimmons Fitzsimmons , Wadleigh Wadleigh , Curran Curran , Kacir Kacir 
Published: December 2007

Abstract
Resistive imaging logs (FMI and EMI) have been embraced by those challenged to characterize flow properties of massive carbonate reservoirs. These logs provide valuable insights for assessment of in situ heterogeneities but are not intended to directly indicate those features that provide the best connections between the wellbore and the formation. High resolution flow surveys of openhole completions in massive carbonates can offer a glimpse of flow capacity that has not suffered cement and perforation damage related to cased completions. Accurate reservoir description can only be accomplished by distinguishing between those features that are effective flow conduits and those that simply appear as large anomalies at the wellbore.
Dynamic Fluid-Loss Studies in Low-permeability Formations with Natural Fractures
Authors: Vinod P. S. , Flindt M. L. , Card R. J. , Mitchell J. P. 
Published: December 2007

Abstract
Dynamic fluid loss through low permeability formations with natural fractures was experimentally investigated in a high-pressure, high-temperature dynamic fluid-loss cell to understand the effectiveness of particulate fluid-loss control additives. The study focused on understanding the relationship between the size distribution and shape of the fluid loss control material on leakoff control and on the cleanup potential.
Sandstone cores of 1-in. diameter and 3-in. length and of approximately 0.05 md were cracked on a press to simulate the naturally fractured low permeability formation. The effective permeability of the fractured cores varied from approximately 0. 05 to 2 md. The effective permeabilities of the fractured cores were measured in situ before and after the leakoff test to quantify damage caused by the external and internal filter cake formation. All tests were conducted at 150°F with linear and borate- or zirconium-crosslinked guar solutions and gels. The wall shear rate across the face of the core was varied by changing the flow rate to simulate a typical fracture shear history at the leakoff face. The core and cell were left overnight at the confining pressure (1500 psi) and temperature before flowing back with brine.
It was found that low-permeability formations with natural fractures have characteristics very similar to those of high-permeability formations. Crosslinked fluids not only are good in reducing fluid leakoff, but also provide higher matrix retained permeability than those obtained with linear polymer solutions. The concept of leakoff control effectiveness, which depends on the leakoff control characteristics and the final cleanup potential, is introduced to quantify the depth of invasion of the polymer (internal filter cake) in the core. The leakoff control effectiveness was used as a tool to compare the relative performances of various fluid-loss additives. The results show that the shape as well as the size distribution of the fluid-loss additive can have a significant impact not only on leakoff control but also on cleanup potential.
Economic Analysis of Horizontal Wells
Authors: Osisanya Samuel O. 
Published: December 2007

Abstract
Horizontal drilling technology has become an economic reality, and the result has been a dramatic upsurge in the number of horizontal wells being drilled. Horizontal wells have proven to be cost effective in optimizing hydrocarbon recovery. Although the majority of wells were drilled because of expected productivity increases, they have not always been a solution to the economic success of the project. As the industry's experience of drilling, completing, and producing horizontal wells increases, so does the realization that horizontal well technology is not always a solution to the problem of more cost effective production. Economic analysis of horizontal well projects are much more complicated than that of vertical well projects because of the many variables involved. Several parameters are evaluated for the economic success of horizontal well projects. These include drilling and completion options, hydrocarbon pay zone thickness, well spacing, fracture intensity, vertical communication, formation damage, and multiwell prospect. The total well cost for the horizontal well is divided into two components: the vertical section cost and the horizontal or lateral section cost. The horizontal or lateral section cost is strongly time-dependent. The type of completion also affects horizontal well performance, and certain completion options are only possible with certain drilling techniques.
This paper presents a step-by-step procedure that can be used when performing an economic analysis of a horizontal well project. The analysis is based on cost estimates associated with all phases of the project. To ensure the economic success of a horizontal well program, multi-disciplinary efforts are required in all preplanning phases of the program. This includes obtaining pertinent information before the well is actually drilled, with a post review of the program after production has been established.
Comparison of the Performance of a Horizontal Dead-End Tee Steam Splitter to a Horizontal Ring Steam Splitter
Authors: Chandler P. J. , Thomas C. A. 
Published: December 2007

Abstract
Mobil Exploration and Producing U. S. ("Mobil") currently uses two different types of steam splitter devices to divide the main steam supply among the steam drive injection wells. The steam splitter's job is to take an incoming stream and divide it into several smaller streams of approximately equal steam quality. The performance of a horizontal dead-end tee steam splitter was compared to a horizontal ring steam splitter to determine which type of splitter did the best job of providing equal quality splits. Performance data from both splitters were taken using a portable test separator while each splitter was in service. The test data show that both splitters provide roughly equal splits among their wells and that neither splitter has a performance advantage. Cost and operating data is presented which will aid the decision as to which type of splitter is appropriate for a given steamdrive project.
Visualization of Steam Injection in Fractured Systems Using Micromodels
Authors: Haghighi M. , Yortsos Y.C. 
Published: December 2007

Abstract
We present visualization studies of hot water and steam injection in micromodel geometries that mimic a matrix-fracture system. Emphasis is placed on the matrix-fracture interaction during steam injection. We visualize the movement of steam and determine the conditions under which matrix penetration by steam occurs. More generally, the effectiveness of steam injection in displacing oil from the matrix is assessed.
Displacement of oil was observed to occur by three mechanisms: a thermally-induced solution gas-drive, capillary imbibition of condensed water and displacement by steam, when the latter penetrated the matrix. Vaporization of light components at elevated temperatures generated an efficient solution-gas drive in the matrix, without the need for steam penetration. This also led to the formation of stable foam-like lamellae, which improved oil production by blocking the movement of steam and water in the fracture. This mechanism was also found to apply during hot water injection. Condensed water imbibed the matrix according to rules that govern imbibition of a fracture-matrix system. Steam penetration of the matrix occurred when the steam rate exceeded a critical value, determined from drainage considerations. The results should be useful in modeling of steam injection in naturally fractured reservoirs.

Introduction
Steam injection is an effective method for the recovery of heavy oil worldwide (Prats, 1982). Steam injection can also be used to recover light crudes, with an efficiency that approaches under certain conditions that of waterflooding Naturally fractured reservoirs are estimated to contain 25-30% of the world supply of deposits (Saidi, 1988). Although of potentially high importance, the application of steam injection in fractured systems, however, is not widely applied.
There exist some obvious differences between displacements in homogeneous and in fractured media. Unlike homogeneous reservoirs, in fractured systems the injected steam does not necessarily sweep uniformly the porous media, but may preferentially flow through the high-conductivity fractures. Furthermore, the mechanism of heating in fractured reservoirs is mostly by conduction, while in a homogeneous system heat is transferred mainly by convection. Therefore, steam injection recovery mechanisms can be quite different in fractured media. Experimental and numerical studies to understand steam injection in fractured systems have been conducted by various investigators. Below, we summarize the most important findings.
Reis (1990) provided a comprehensive review of oil recovery mechanisms in steam injection in fractured reservoirs. Thermal expansion and gas generation were described as two key mechanisms. In the first, the expansion of fluid and rock minerals at high temperatures result in the expulsion of fluids from the matrix to the fracture. A differential thermal expansion of the order of 0.05%/ F was estimated by the combination of porosity reduction and fluid expansion. P. 67
More Oil from Better Information: New Technological Applications for Testing Producing Wells
Authors: Christianson Bruce A. 
Published: December 2007

Abstract
Producing Operations are developing advanced tools in response to the challenge of maximizing oil recovery and minimizing operational costs. Oil and water volumes from producing wells are measured by well gauge systems. Poor gauge system performance can mask true well output, at the expense of well optimization decisions.
In Texaco's Bakersfield Division, two statistical analysis techniques, Process Capability Index (PCI) and Confidence, are being used to improve gauge systems so that true well performance can be analyzed.
Compositional Input for Thermal Simulation of Heavy Oils With Application to the San Ardo Field
Authors: Lolley C. S. , Richardson W. C. 
Published: December 2007

Abstract
Significant compositional changes have been recently documented in laboratory analyses of remaining oil in core samples from mature steamfloods. In order to properly account for these changes, the production of hydrocarbon condensate (casing blow) from heavy oil reservoirs, and the formation of an in-situ solvent bank, a fully compositional, equation-of-state approach in thermal reservoir simulation is needed. Dead oil thermal simulation will not account for these recovery mechanisms.
A survey of equation-of-state development for lighter oils reveals that traditional methodologies using a C7+ heavy split with a gamma distribution and α=1 may not be correct for some medium to heavy oils. Extensive gas chromatography (GC) analyses reveals a "double hump" or bimodal compositional distribution in some medium to heavy oils. This bimodal distribution is often overshadowed in lighter oils due to increased presence of C1-C6 components. Because of this bimodal distribution and absence of significant C1-C6 composition, a different methodology and series of laboratory test must be used to develop equation-of-state parameters as well as account for complex interactions between polar water molecules and non-polar hydrocarbon molecules which occur in the process of steamflooding. This data is then used to tune equation-of-state parameters for use in compositional thermal simulation. This new technique is presented as an alternative model for EOS parameter development for medium to heavy oils and is more economical than previous methods which require a full ASTM-2892 distillation. San Ardo crude oil (120API) is used to demonstrate the technique. The full 40 component model can then be pseudoized into fewer components for field scale simulation.
Improving HPHT Stability of Water Based Drilling Fluids
Authors: Oort Eric van , Bland R. G. , Howard S. K. , Wiersma R. J. , Roberson Loyd 
Published: December 2007

AbstractA new method is discussed to improve the HPHT stability of conventional rheology modifiers and fluid loss polymers used in water-based drilling fluids. The method exploits the interactions of polysaccharides (e.g. xanthan gum, scleroglucan), cellulosics (e.g. CMC, PAC) and starches with polyglycols. Polymer and polyglycols were found to associate by inter-molecular hydrogen bonding and hydrophobic interactions. This association / complexation was found to stabilize the polymers at higher temperatures. Our laboratory findings are validated by field observations in the Kakap field in Indonesia that show improved HPHT stability when adding polyglycols to water-based drilling fluid formulations.
Optimization of Multiple Bit Runs
Authors: Barragan R. V. , Santos O. L. A. , Maidla E. E. 
Published: December 2007

Abstract
Optimization of single bit runs to achieve the minimum cost per meter has been discussed and published quite extensively throughout papers, journals, and other periodicals. Very little has been said and done concerning multiple bit runs that is the case for over 90% of the wells drilled worldwide. The reason for this is that the problem is much too complex to be solved with a set of analytical equations due to the interdependence of some of the drilling model coefficients, the uncertainties associated with the parameters involved such as the rock type, strength and mechanical properties, and a good handle on the historic operating conditions and bit grading.
A research program was commissioned to address this based on an heuristic approach to seek the optimum conditions using Monte Carlo Simulation and specially developed numerical algorithms. The output of the program yields the operating conditions for each individual bit run so that the overall cost are minimized for the entire well phase drilled.
The method does not depend on a particular drilling model and has been tested with several models such as Bourgoyne&Young's, Warren's and others. The paper shows results of using the first two models mentioned due to their greater acceptance within the very small portion of the drilling industry that uses drilling models at all.
The results show an average cost per meter savings of over 10% in most cases and can be as high as 30% depending on the length to be drilled and the number of bits required.
New Solutions to Remedy Lost Circulation, Crossflows, and Underground Blowouts
Authors: Sweatman R. E. , Kessler C. W. , Hillier J. M. 
Published: December 2007

Abstract
Costly lost circulation, crossflows, and underground blowouts result in mud losses, wasted rig time, often ineffective remediation materials and techniques, and sometimes lost holes, sidetracks, abandoned wells, relief wells, and lost petroleum reserves. In early 1996, a service company initiated a project to review conventional remediation materials and methods, search for more effective remedies, and field-test new solutions. The project has led to the development of several novel lost-circulation material squeeze systems (LCMSS). These LCM squeeze systems were applied in wells after conventional materials/ methods failed, and they successfully cured lost circulation, increased the integrity and frac gradient (FMW) of weak zones (formations with low mechanical strength), sealed high-pressure water and gas zones, safely allowed deeper drilling, and stopped underground blowouts. Data from these field tests show encouraging trends and prospects not only to save costs associated with drilling trouble, but also to reduce normal exploration and production costs for casing, liners, drilling/completion fluids, rig time, poor primary cementation, remedial cementing, and water production.
A Novel Technique for Predicting End-Point Relative Permeabilities of Heterogeneous Limestones from Log Derived Input Data
Authors: Kalam Mohammed Zubair , Al-Alawi Saleh M , Al-Shekaili Suhail 
Published: December 2007

Abstract
Artificial neural network models are increasingly prevalent in predicting various reservoir engineering parameters. The petroleum engineering community at large is witnessing a surge in the use of expert systems and artificial neural networks related technologies, within the broader domain of artificial intelligence. These relatively new computer based tools provide answers to a number of engineering problems which are usually expensive to quantify experimentally, and at the same time reduce the uncertainties inherent in many of the measurement techniques.
Kalam and Al-Alawi1-4 have successfully applied artificial neural network (ANN) derived models to assess formation damage in limestone formations, and prediction of wettabilities of cores from diverse producing carbonate reservoirs in the Sultanate of Oman. The ANN predictions were then compared with measured data, and a number of established empirically derived correlations (commonly used in typical reservoir simulation studies).
The developed ANN models provide quick and fairly accurate predictions of the end-point relative permeabilities of reservoir cores from naturally fractured heterogeneous reservoirs, using simple log derived input parameters. Errors in estimating in these important reservoir characterisation properties from a number of widely used correlations are significantly higher than the experimental measurements. The relative permeability curves from ANN models predictions are consistent with those determined from the tedious and rather expensive SCAL programmes, and as such reduce the uncertainties in reservoir simulations.
3-D Reservoir Characterization for Improved Reservoir Management
Authors: Uland M. J. , Tinker S. W. , Caldwell D. H. 
Published: December 2007

Abstract
Three dimensional (3-D) reservoir characterization tools have reached a development stage where they can be used cost-effectively to help solve reservoir management problems. A principle goal of 3-D reservoir characterization is to derive a spatial understanding of inter-well heterogeneity using integrated geophysical, geological, and engineering data. Traditionally, geologic attempts to characterize interwell heterogeneity have been done using hand-drawn or computer generated 2-D maps and cross-sections. Results can be dramatically improved using 3-D interpretation and integrated analysis techniques. The end product of 3-D reservoir characterization is a more accurate 3-D reservoir model that can optimize answers to reservoir management questions.
Three-dimensional reservoir characterization requires the same input data as 2-D methods, does not add to reservoir characterization costs, improves the integrity of the geologic interpretation, and requires less time than equivalent projects done in 2-D. Updates can be made to the full-field 3-D integrated model within days, as opposed to weeks or months for equivalent changes in a 2-D modeling environment. The enhanced speed allows the user to make several versions of a 3-D model to capture the range of stratigraphie and depositional possibilities. This results, ultimately, in a more accurate 3-D reservoir description.
Five case studies will be presented, including a proximal turbidite, middle-shelf carbonate, two outer-shelf carbonates, and a distal turbidite field. For each field, a synopsis of the reservoir management problem, geology, available data, 3-D model solution, and reservoir management benefits will be presented. Several case studies illustrate data quality control, volumetric calculations, improved reservoir management decisions, and communication between disciplines.