bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advantages of a New Chemical Delivery System for Fractured and Gravel- Packed Wells
Authors: Webb P. J. C. , Nistad T. A. , Knapstad Borge , Ravenscroft P. D. , Collins I. R. 
Published: December 2007

Summary
The deposition of scale, such as carbonates and sulphates, in production facilities represents a serious operational problem that can result in significant well productivity decline. Current scale control strategies can involve significant capital and operational expenditure.
Development work, involving laboratory testing and a field trial, has demonstrated the technical benefits of a revolutionary method of downhole scale inhibitor delivery that can prevent scale deposition for a significant proportion of a well's lifetime. The method involves the slow release of scale inhibitor from porous proppants.
Economic analysis indicates that significant benefits can be derived for a variety of field development and well completion types. The greatest economic benefits would be realized for subsea and minimum facility installations with high intervention costs, where squeeze delivery of inhibitor or mechanical workover are used for scale control. In addition, major economic benefits can be realized for horizontal wells with unfavorable pressure regimes, multilateral-type completions, multiple fractured wells, and many conventional completion types.
The new chemical delivery method offers cost reduction through reduced deferred oil, efficiency of chemical usage, and fewer workovers using coil tubing and intervention vessels. Economic analysis has indicated that for some conventional and advanced well types, fracturing a well and deploying proppant impregnated with scale inhibitor, is economically preferable to a conventional strategy of squeeze treatment in an unfractured well.
An additional economic benefit of proppant impregnated with scale inhibitor is increased well productivity. The benefit is derived from the combined effect of improved gel breaking, and scale inhibition during well cleanup. This has been demonstrated in laboratory testing and would appear to be confirmed by field observations.
A further benefit of applying scale inhibitor as chemically impregnated proppant is the immediate treatment of produced water when water breakthrough occurs. This feature avoids the formation damage that can occur before squeeze treatment mobilization. In addition, for some applications involving large fractures there is the potential for lifetime well treatment.
This paper describes the laboratory work, the field trial, and the economic benefits of the new product.
Combustion/Oxidation Behavior of Athabasca Oil Sands Bitumen
Authors: Moore R. G. , Laureshen C. J. , Ursenbach M. G. , Mehta S. A. , Belgrave J. D. M. 
Published: December 2007

Summary
Oils that are potential candidates for in situ combustion recovery processes are often screened by means of their oxidation characteristics: in particular, the kinetics of the ignition process and the transition from low-temperature to high-temperature oxidation through what is known as the "negative temperature gradient region." These characteristics are readily studied in ramped-temperature oxidation tests, which involve the controlled heating of recombined, oil-saturated cores in a one-dimensional plug flow reactor under a flowing stream of air (or oxygen-containing gas). The purpose of these tests is to study the global oxidation behavior and reaction kinetics under controlled conditions, with the end purpose of providing realistic data for incorporation into a numerical simulator which can be used to predict field performance.
A ramped-temperature oxidation apparatus was used to conduct a detailed, two-year parametric study of the oxidation characteristics of Athabasca Oil Sands bitumen. The text matrix involved various levels of pressure, gas injection rate, oxygen content of the injected gas, and maximum ramp temperature. This paper details the principal findings for the 45-test study; especially the need to maintain high reaction temperatures (&gt; 380° C) in order to mobilize and produce heavy oils under conditions of dry in situ combustion. Design considerations and operational guidelines for successful field projects arising from the results of this study are also discussed.
Modeling Multicomponent Diffusion and Convection in Porous Media
Authors: Ghorayeb Kassem , Firoozabadi Abbas 
Published: December 2007

Summary
Numerical investigations of diffusion and convection in multicomponent hydrocarbon mixtures in two-dimensional (2D) crosssectional (x,z) porous media are performed using the finite-volume method. Spatial discretization is performed by a second-order centered scheme. It is shown that methane, unlike in binary hydrocarbons where it often segregates towards the bottom-hot side of the porous media, may be at higher concentration at the cold-top side in ternary mixtures and in multicomponent reservoir fluids. This behavior, which is consistent with oilfield data, is due to competing diffusion mechanisms which have not been properly accounted for in the past. It is also demonstrated that convection may significantly affect the compositional variation in some hydrocarbon reservoirs. Depending on fluid mixtures, a weak convection may drastically change compositional variation.
Investigation of Fluid Conductive Faults and Modeling of Complex Water Influx in the Khafji Oil Field, Arabian Gulf
Authors: Nishikiori N. , Hayashida Y. 
Published: December 2007

Summary
This paper describes the multidisciplinary approach taken to investigate and model complex water influx into a water-driven sandstone reservoir, taking into account vertical water flux from the lower sand as a suspected supplemental source.
The Khafji oil field is located offshore in the Arabian Gulf. Two Middle Cretaceous sandstone reservoirs are investigated to understand water movement during production. Both reservoirs are supported by a huge aquifer and had the same original oil-water contact. The reservoirs are separated by a thick and continuous shale so that the upper sand is categorized as edgewater drive and the lower sand as bottomwater drive. Water production was observed at the central upstructure wells of the upper sand much earlier than expected. This makes the modeling of water influx complicated because it is difficult to explain this phenomenon only by edgewater influx.
In this study, a technical study was performed to investigate water influx into the upper sand. A comprehensive review of pressure and production history indicated anomalous higher-pressure areas in the upper sand. Moreover, anomalous temperature profiles were observed in some wells in the same area. At the same time, watered zones were trailed through thermal-neutron decay time (TDT) where a thick water column was observed in the central area of the reservoir. In addition, a three-dimensional (3D) seismic survey has been conducted recently, revealing faults passing through the two reservoirs. Therefore, as a result of data review and subsequent investigation, conductive faults from the lower sand were suspected as supplemental fluid conduits. A pressure transient test was then designed and implemented, which suggested possible leakage from the nearby fault. Interference of the two reservoirs and an estimate of supplemental volume of water influx was made by material balance.
Finally, an improved full-scale numerical reservoir model was constructed to model complex water movement, which includes suspected supplemental water from the lower sand. Employment of two kinds of water influx—one a conventional edge water and another a supplemental water invasion from the aquifer of the lower sand through conductive faults—achieved a water breakthrough match.
Low-Field NMR Method for Bitumen Sands Characterization: A New Approach
Authors: Mirotchnik K. D. , Allsopp K. , Kantzas A. , Curwen D. , Badry R. 
Published: December 2007

Summary
The nuclear magnetic résonance (NMR) signal obtained from conventional oil, heavy oil, and bitumen formations can consist of both hydrocarbon and water signals. Each NMR signal can further characterize both mobile and immobile fluids in the porous media. However, as the viscosity of the hydrocarbon phase increases and the NMR signal shifts toward lower relaxation times, the composite NMR signal for the hydrocarbon-bearing formation becomes very complicated. As the viscosity of the bitumen exceeds 100,000 cp (at natural conditions), the relaxation characteristics of bitumen become partially nondetectable by both the logging and laboratory NMR tools. As a result, the conventional methods of NMR detection fail to precisely recognize the hydrocarbon components.
Laboratory NMR measurements of bitumen-bearing porous media under different temperatures were performed. This method delivered new information about bitumen reserves in situ. The results show that low-field NMR holds promise for the characterization of recoverable heavy oil and bitumen reserves. This new approach can be applicable for real-time monitoring of thermal extraction, including monitoring the efficiency of thermal recovery methods.
Real-Time Monitoring and Control of Water Influx to a Horizontal Well Using Advanced Completion Equipped With Permanent Sensors
Authors: Bryant I. D. , Chen M. -Y. , Raghuraman B. , Schroeder R. , Supp M. , Navarro J. , Raw I. , Smith J. , Scaggs M. 
Published: December 2007

Summary
We have tested new technologies for real-time monitoring and control of water influx to horizontal wells with sand-control completions. In a thin oil column in Indiana, we drilled a horizontal well and completed it openhole with sand screens and a gravel pack. External casing packers (ECPs) subdivided the annulus into three zones. An electrical valve, which also records the annular and tubing pressure, controls inflow to each zone. Twenty-one centralizers acted as electrodes to form a resistivity array that spans the 694-ft-long completion. The well was also equipped with a fiber-optic distributed-temperature-sensing (FODTS) system. The well has been produced since November 2001 and provides real-time data that are shared across a geographically distributed network and used to optimize the production of oil from the well.
The data from the pressure sensors and the resistivity array have been jointly interpreted to dynamically update the static reservoir model, which was initially based on observations in offset vertical wells. The pressures recorded from the three electrical valves provide high-frequency data to characterize the near-well heterogeneity of the formation. These data are critical to computing an optimum production strategy. Zonal well tests, combined with interference testing between zones and wells, enable the estimation of communication between zones and the productivity index (PI) of each zone. The resistivity data enabled detection of water-saturation changes both in the formation and in the wellbore.
The completion technology tested in this well offers the potential to intelligently operate horizontal sand-control completions by combining real-time monitoring with downhole inflow control.
Effect of Nonuniform Loading on Conventional Casing Collapse Resistance
Authors: Pattillo P. D. , Last N. C. , Asbill W. T. 
Published: December 2007

Summary
In various locations worldwide, casing designers are confronted with nonuniform cross-sectional loading caused by contact with a mobile formation. The formation movement may be the result of rock constitution (salt, swelling shale), or it may be tectonic in origin.
Typically, well design proceeds with the goal of combating the nonuniform load. If this load occurs slowly, adjustments to the tubular design may be minimal, as the cross-sectional ovalization can only occur at the same rate as the formation movement. Adopting such an approach, however, ignores the fact that ovalization of the cross section because of nonuniform loading may also lower its collapse resistance to more conventional loads such as pressure differential (e.g., external pore pressure minus internal fluid pressure).
This paper documents the results of numerical and experimental studies to determine the effect of nonuniform loading on the conventional collapse resistance of casing. The current work focuses on casing exposed to external fluid pressure and extreme point loading, as might be the case in a poorly cemented wellbore.
An introductory section sets forth the problem with a specific design scenario for a production casing string loaded simultaneously by imposed ovalization caused by tectonic formation movement and collapse differential from the local fluid environment. The load is then simplified and solved numerically. The numerical results are first justified by physical argument, and then validated by full-scale collapse testing. Finally, the distinction between manufactured and imposed ovality is reinforced by comparison of the results with conventional collapse equations.
Factors Affecting Scale Inhibitor Retention in Carbonate-Rich Formation During Squeeze Treatment
Authors: Kan Amy T. , Fu Gongmin , Tomson Mason B. , Al-Thubaiti Musaed , Xiao Alan J. 
Published: December 2007

SummarySignificant progress has been made toward developing a quantitative understanding of the inhibitor/rock interaction. In this study, four common oil field inhibitors (three phosphonates and one polyacrylate) are compared using carbonate-rich formation material. In addition to calcite (CaCO3) in the reservoir rock, several calcium inhibitor (Inh) solid phases are also important. Two reactions are central to the inhibitor retention in carbonate-rich formation: first, reduction of calcite dissolution because of surface poisoning by the Ca-Inh coating; and second, precipitation of Ca-Inh solid with either low Ca or high Ca stoichiometry. For NTMP, an acidic Ca-NTMP salt is formed at a low-pH environment. In addition, two crystalline Ca-NTMP phases and an amorphous Ca-NTMP salt may form, depending on the aquatic environment. Quantitative relationships between types of inhibitors, inhibitor acidity and concentration, and kinetics of calcite dissolution and calciumphosphonate precipitation are developed. Consequences of the observations on squeeze design and scale inhibition will be discussed.
Mechanism of Crude-Oil/Water Interface Destabilization by Silicone Demulsifiers
Authors: Dalmazzone C. , Noïk C. , Komunjer L. 
Published: December 2007

SummaryOil exploitation is always accompanied by the nondesired formation of emulsions caused by the presence of naturally occurring surface-active molecules such as asphaltenes and resins. Because their presence stabilizes the oil/water interface, it is necessary to break the emulsions by adding other surface-active molecules. Formulations based on polysiloxane molecules were selected as effective nontoxic products to enhance the oil/water phase separation. Establishing the relation between the efficiency of formulations and the interfacial properties of silicone molecules is the objective of this study. Formulation selection is based on bottle tests using turbidimetric measurements and on dynamic tests using a "dispersion rig" setup that allows the formation of emulsions under pressure and temperature conditions and injection of additives into the formed emulsion online. Rapid kinetics of separation and high levels of separated water were observed. Dynamic interfacial measurements were performed using complementary techniques. The drop-volume technique allows the measurement of the evolution of crude-oil/water interfacial tension with time. The Langmuir trough technique is used to obtain 2D compression isotherms and to deduce the elastic properties of interfaces. The coalescence of water droplets leading to the destabilization of emulsions and consequently to the oil/water separation efficiency can be related to the rheological properties of water/crude-oil interface. Therefore, such comprehensive study based on a specific methodology can lead to a strict and effective selection of emulsion breaker additives in relation with the oil composition.
The Application of High-Power Sound Waves for Wellbore Cleaning
Authors: Champion Brian , van der Bas Fred , Nitters Gerrit 
Published: December 2007

SummaryThis paper presents the results of a wide-ranging investigation into the application of high-power sound waves to remove plugging material from the wellbore and near-wellbore regions. This paper describes the process of generating high-power sound waves with a high-voltage electrical discharge and summarizes the results of the laboratory and test-well trials conducted on both simulated plugging materials and mudcake. The paper also references the development progress of a prototype wireline-conveyed, wellbore-cleaning system. The results of the investigation concluded that high-power sound waves represent a viable wellbore-cleaning technology with the potential to be applied effectively in removing various forms of wellbore-plugging material. Because this process can be applied selectively and in a controlled manner in the wellbore, without environmental impact and with standard wireline-deployment techniques, it offers considerable benefits vs. some existing solutions.
Perforating in Overbalance—Is It Really Sinful?
Authors: Chang F. F. , Kageson-Loe N. M. , Walton I. C. , Mathisen A. M. , Svanes G. S. 
Published: December 2007

Summary
Drilling and completing long horizontal wells in North Sea oil fields is extremely costly. When perforating these long horizontal sections (&gt;1000 m), deployment of the perforation guns on drill-pipe has been regarded as the safest and most cost-efficient method. The well is then kept in overbalance until the completion is installed.
To maintain well control, a fluid with loss-control capability [kill pill (KP)] is used as completion fluid during perforating to seal the formation immediately after perforating. This saves the time required to displace completion brine and the cost of losing the expensive brine into the formation. However, perforating with the kill fluid in the wellbore presents a great challenge in mini-mizing formation damage. Therefore, optimizing the perforating design and choosing the proper kill fluid are crucial tasks to ensure good well productivity. A thorough laboratory testing program has been performed to re-evaluate perforating strategy and completion-fluids selection for several fields in the North Sea. The fluid systems investigated include oil-based mud and water-based KPs formulated from formates and bromide brines.
The laboratory results have shown that if the perforating is designed and executed properly, formation damage can be reduced to a minimum even during overbalanced perforating. In this work, the major damage appears to be from the kill fluids. When using a water-based KP, the reduction in relative permeability appears to be an important damage mechanism. Therefore, the productivity is influenced strongly by the fluid-loss-control capability. In contrast, filtrate invasion from the oil-based mud does not alter relative permeability; therefore, the formation damage shown in these tests is less pronounced.
Furthermore, zinc- and steel-cased charges have been used to investigate their compatibility with kill fluids and their impact on formation damage. These studies have shown that interaction between zinc and CaBr2-based KPs can cause failure of fluid-loss control and excessive invasion of filtrate, leading to severe productivity impairment.
This paper presents some of the results of the laboratory testing program.
Influence of Drill-in Fluids Composition on Formation Damage
Authors: Sánchez Erna , Audibert-Hayet Annie , Rousseau Lionel 
Published: December 2007

SummaryDrill-in fluids are generally water-based muds (WBMs) containing a viscosifier, a fluid-loss reducer, salts, and sized calcium carbonate particles. Formation damage mechanisms induced by the use of WBM formulations have been extensively studied and correspond to different phenomena such as water trapping, polymer adsorption and retention, and particle plugging. In this paper, a detailed study was carried out on the behavior of scleroglucan-based formulations generally proposed for high-temperature zones and/or high-permeability reservoirs and on the comparison with performances of xanthan-containing formulations. This work covers not only the effect of the fluid composition, including the presence or absence of drilled solids, but also the filtration conditions, such as shear rate and temperature. Mud filtrates have been characterized in terms of polymer content and by multiangle laser light scattering coupled with size-exclusion chromatography (SEC/MALLS) and filter cakes by cryo-SEM.Filtration curves obtained under static conditions can be related to the rheological behavior and thermal stability of the biopolymer used as a viscosifier but not related to the solid content of the mud. Under dynamic conditions, the filtration curve strongly depends on the aggregation tendency of the scleroglucan sample.Scleroglucan-based drill-in fluids present very good properties compared to classical water-based formulations at 120°C using a commercially available scleroglucan sample. The cryo-SEM dynamic filter-cake observations confirm a lower filter-cake permeability obtained under dynamic conditions with an homogeneous structure, no aggregates, and a structural polymer network.When in contact with a borehole, for the same circulation time, a scleroglucan formulation will invade half the zone invaded by a xanthan-based formulation.
One Approach to the Grid Orientation Problem in Reservoir Simulation
Authors: Vinsome Paul K. , Au Anthony D. K. 
Published: December 2007

Abstract
Consider a linear, incompressible, two-phase flow in the absence of capillary pressure. Assume that a saturation shock front exists as depicted schematically in Fig. 1, and that the mobility behind the front is extremely high. During any time step of a numerical simulation, the exact position of the shock front generally is not known, so we assume that in an average sense the position of the shock may be placed midway between the nodes. In any numerical reservoir simulator that contains an upstream formulation, the value of Ss on Fig. 1 would be representative of the saturation at which the interblock phase mobility is evaluated. This would result in the calculation of the pressure profile shown by the solid Line P. There is clearly some inconsistency, as the true pressure profile is more like the dashed Line P′. Therefore, one possible source of the grid orientation effect is that the upstream finite-difference formulation produces far too small a pressure drop across a shock front, and that the directionally dependent pressure field truncation error is a significant fraction of this pressure drop.
Equating fluid velocities on either side of the shock front gives
where λT represents the total fluid mobility. If the pressure at the shock front ps is eliminated from these equations, we obtain
whereby it can be seen that the total effective mobility is given by
The harmonic mobility given by Eq. 3 is closer to twice the smaller value of (λTu, λTd) than to the upstream value, so it has the capability of producing larger pressure drops across a shock front.
On Fig. 1, it can be seen that the fluid fraction flowing at the shock front is more similar to the upstream value. This suggests that for the individual phase mobilities an upstream formulation should be used: