bluuebunny/crossref_metadata_2025_split huggingface dataset:
Brine and Permeability Effects on Crosslinked Fluid-Loss Pill Filter-Cake Formation
Authors: Vollmer D. P. , Lejeune B. E. 
Published: December 2007

Abstract
During completion and workover for the recovery of oil and gas, fluid loss pills are used to control completion brine losses to the formation. Basically, the operator has three types of fluid loss pills to choose. They are linear water soluble polymers like hydroxy ethylcellose (HEC), solids laden, and the most recent crosslinked pills. Since both HEC and crosslinked pills are considered solids free, crosslinked pills are more effective on higher permeability formations by the formation of a polymer filter cake. However, little work has been done to define the permeability limit for these crosslinked pills and when an operator should use a solids laden pill instead of a crosslinked one. Also, the brine type effects the overall efficacy of the fluid loss pill. Therefore, lab tests were conducted to address these issues by evaluating a crosslinked zirconium carboxy methyl hydroxy ethyl cellulose (CMHEC) pill. The tests showed that as the calcium halide increases the ability for filter cake formation for this crosslink pill decreases with permeability. For example, for crosslinked CMHEC in water at 180°F, the limit is less than 20 Darcy (60 micron) but in a 14.2 ppg calcium bromide solution; the limit is less than 2 Darcy (10 micron). Other variables like pH and temperature are discussed to provide guidelines.
Chemical Demulsifier Development Based on Critical Electric Field Measurements
Authors: Beetge J. H. , Horne B. O. 
Published: December 2007

Abstract
Resolution of water and oil emulsions is critical to the oil field industry. A wide variety of undesirable emulsions are formed during the production, handling and processing of crude oil. Although various methods are used, dehydration of crude oils is mostly achieved by gravitational sedimentation, normally at elevated temperatures and with the addition of chemical demulsifiers.
The quantitative evaluation of emulsion stability by a Critical Electric Field (CEF) technique was developed to play a significant role in chemical demulsifier research. It was found that the CEF technique is not only useful in the evaluation of water-in-oil emulsion stability, but also in studying the mechanisms of stabilization as well as demulsification.
A method was developed to study the mechanism of emulsion stabilization in terms of flocculation and coalescence behavior of a crude oil emulsion. The effect of chemical demulsifiers on emulsion stability was evaluated in terms of the method developed in this study. By following this approach, it is possible to determine the relative amount of energy required for both flocculation as well as coalescence, in the presence of a chemical demulsifier.
H2S Scavengers for Non-Aqueous Systems
Authors: Buller J. , Carpenter J. F. 
Published: December 2007

Abstract
Hydrogen Sulfide (H2S) is problematic in oilfield systems because of its high toxicity and corrosive nature. There are a number of technologies available to remediate sour production streams containing water. However, technologies to effectively and quickly scavenge water-deficient, oil systems are limited.
In this paper we review the properties of a family of new, fast-acting, oil-soluble H2S scavengers based on carboxylates of zinc and iron. Laboratory and field performance data are presented. This technology's efficacy is demonstrated in a plant trial treating a 1200 ppm hydrogen sulfide contaminated oil-stream. A range of competing oil- and water-soluble scavengers was shown to be less effective under these conditions.
Paraffin Crystal and Deposition Control By Emulsification
Authors: Ahn S. , Wang K. S. , Shuler P. J. , Creek J. L. , Tang Y. 
Published: December 2007

Abstract
This laboratory investigation considers the effects of emulsions (via adding surfactants) and the formation and deposition of paraffin wax. This study relates the properties of added surfactant and emulsion characteristics with their wax deposition tendency. Parameters considered include the surfactant HLB (Hydrophilic Lipophilic Balance), molecular weight, and surfactant concentration. Two different series of commercial nonionic surfactants are included in this study; Triton-X (ethoxylated phenols) and Tween (sorbitan) products. The hydrocarbon phase is a model oil; a mixture of paraffin's with carbon numbers from C21 to C48 dissolved in n-decane (C10). Emulsion characterization was done by IFT (interfacial tension), viscosity measurement, and optical microscopy. The wax deposition measurements were performed in a novel cell apparatus where stirring controls the hydrodynamics and mixing energy.
The study results indicate adding surfactants to promote emulsification can reduce the tendency for wax deposition. Properties that induce tighter emulsions such as lower interfacial tension and greater shear rate lead to reduced paraffin deposition. Furthermore, the wax that does deposit from an emulsion is softer (lower average molecular weight) versus wax that deposits in the absence of any chemical. In contrast, the wax that deposits in the presence of some commercial polymer-based wax inhibitors can be even harder (higher average molecular weight) than the deposit formed in the absence of any chemical additive.
Improved Accuracy of Modeling for Optimization of Squeeze Design
Authors: Mackay E. J. , Al-Mandhari S. , Peacock J. , Hammond B. 
Published: December 2007

Abstract
Scale inhibitors may be injected periodically into production wells to prevent loss of productivity due to scale deposition. These squeeze treatments are routinely modelled and optimised using near-wellbore simulators. Typically these calculations assume that inhibitor distribution along the wellbore is controlled by the permeability length product, kh, (measured in mD.ft or mD.m). However, most reservoir engineering calculations performed using a reservoir simulator assume that production profiles may also be controlled by a variety of other parameters, such as wellbore friction (in horizontal wells), interval pressures (in reservoirs with non-communicating layers), well orientation, etc.
This paper describes the comparison of squeeze life calculated using a simple near-well simulator where inhibitor injection profiles assume that placement is controlled entirely by the kh factors, with calculations which are also performed using a near-well simulator, but in which reservoir simulation data is used to account for the influence of other parameters. In this study, 26 wells from one field were studied. For the majority it was demonstrated that assuming the injection profile would follow the kh profile was quite adequate. However, in five wells inhibitor placement was shown to be dominated by factors other than the kh product, and thus squeeze modelling that takes account of these other factors (wellbore friction and crossflow) would render significantly more accurate predictions of squeeze performance.
Knowledge of injection and production profiles derived from the field model was then used to optimise the design of squeeze treatments in two wells. The objective here was not only to maintain/extend squeeze life, but also to reduce the period during which process upsets were occurring post squeeze due to high concentrations of inhibitor causing emulsion bands and reducing separator efficiency. Previously published simulation work had demonstrated that by increasing the overflush volume, the concentration at which inhibitor would flow back in the first few hours of production would be reduced. This was validated by field results. However, in some cases the reduction in concentration was not sufficient (&lt;1,000 ppm), and in fact the period during which process upsets were occurring increased. This was because in these cases, although the height of the concentration spike was reduced, it was not reduced sufficiently, and in the process the spike was broadened. Calculations were therefore performed to evaluate how much further the overflush would have to be increased to reduce the height of the spike below the level at which it was considered process upsets would not occur. The benefit of this was then evaluated relative to any increase in squeeze life on the one hand, and issues related to lifting the injected water and the well downtime with resulting deferred oil on the other hand.
Phase Redistribution and Horizontal Well Effects on Black-Oil Model of a Rich Gas Condensate Reservoir
Authors: Izgec B. , Barrufet M. A. 
Published: December 2007

Abstract
The black-oil model (MBO) of a gas condensate reservoir was tested against the fully compositional model and performances of both models were compared using various production and injection scenarios.
We evaluated the performance of MBO model by investigating: the effects of black-oil PVT table generation methods from a tuned equation-of-state, oil-gas ratio (OGR) and saturation pressure versus depth as initialization methods, uniform composition versus compositional gradient with depth, location of the completions, production and injection rates, kv/kh ratios, and vertical wells versus horizontal wells.
Contrary to the common belief that OGR versus depth initialization gives better representation of original fluids in place, initializations with saturation pressure versus depth gave closer original fluids in place considering the true initial fluids in place are given by the fully compositional model initialized with compositional gradient.
Unrealistic vaporization in the MBO model was encountered in both, production by natural depletion, gas cycling and as well as during the shut-in period of the producer. The changes in oil-gas ratio of the recyled gas showed that, it is not possible to accurately represent the changing PVT properties of the recycled gas with a single PVT table. Unrealistic vaporization also led to different arrival times for the displacement fronts and different saturation profiles for the near wellbore area and for the entire reservoir for the two models even though the production performance of the models was in good agreement.
The MBO model representation of compositional phenomena for a gas condensate reservoir proved to be adequate for full pressure maintenance, reduced vertical communication, vertical well with upper completions, and for horizontal well producers.
Possible Mechanism of the Drag Reduction Phenomenon in Light of the Associated Heat Transfer Reduction
Authors: Hamouda A. A. , Evensen F. S. 
Published: December 2007

Abstract
Drag reduction phenomenon has been known for more than 55 years. The mechanism by which friction reduction occurs has been a subject of intense discussion since its discovery in 1947. It has been reported previously the mutual influence of the polymer drag reducers (DRA) and the paraffin deposition in pipelines. In order to understand this effect, as a first step, a study of the heat transfer in presence of DRA is addressed in this paper.
Onset wall shear stresses (critical shear stress-tw*) are determined for two heat transfer conditions (40/32 and 40/28°C) of a crude oil/water heat exchanger system in presence of two types of oil soluble DRA (having the same chemistry but the average molecular weight of DRA1 is about 5 times higher than that for DRA2). The onset wall shear stresses are about 7.9 and 9.0 N/m2 for the first and second heat transfer conditions, respectively. Both polymer solutions showed same values at the corresponding heat transfer conditions.
The paper discusses the effect of the DRA polymers on heat transfer and suggests possible mechanism for the drag reduction in pipeline. It also suggests explanation on some of the observation in literature in laboratory compared to the field data.
Downhole Scale Formation and Inhibition in Mild Sulphate Scaling Conditions
Authors: Stalker R. , Graham G. M. , Hellings G. , Williams Joanne C. , Littlehales I. 
Published: December 2007

Proposal
The presence of a mild scaling regime in a field necessitates effective measures to be taken to prevent scale formation before production is adversely impacted. However, in many cases the scaling regimes are too mild to be investigated by conventional laboratory inhibitor test protocols under realistic timescales. In such cases, laboratory testing of inhibitor chemicals can often be achieved by conventional methods only by artificially increasing the severity of the scaling regime, and thus potentially underestimating the field performance of the inhibitor. A novel dynamic core blocking test procedure which allows laboratory evaluation of inhibitor performance in such mild scaling regimes within realistic timescales has been developed and applied to a field-specific case. In this paper, we report the further development of this test method. We describe a field example in which inhibitor performance and inhibitory mechanism have been examined using this method, allowing scale squeeze treatments to be recommended at lower percent sea water breakthrough of ~ 30 % rather than the originally planned level of ~ 50%.
Use of Low-Dosage Hydrate Inhibitors in Sour Systems
Authors: Thieu V. , Frostman L. M. 
Published: December 2007

Abstract
Low-dosage hydrate inhibitors (LDHIs) continue to gain acceptance as alternatives to traditional hydrate control techniques. While these products have been in use for numerous years, there have been few reports of the use of LDHIs in sour systems. Hydrogen sulfide (H2S) has long been known to affect the conditions at which hydrates become stable. Often, the presence of percent levels of H2S significantly increases the temperature at which hydrates can form in hydrocarbon production and transmission systems compared to the corresponding sweet system. Many questions have been raised as to whether the presence of H2S affects the performance of LDHIs. While LDHI performance tests in sweet systems have become routine, it is very difficult to test LDHI performance in the presence of significant H2 S. Despite the difficulties in studying LDHIs in sour systems in the laboratory or pilot scale tests, several field applications of LDHIs have been conducted over the last several years. This paper will detail five case histories of successful field applications of both kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) in sour systems. The results show that LDHIs can indeed be used effectively to control hydrates in sour systems.
Screening and Selection of Alternative Hydrate Inhibitors Using a Model Apparatus Under Dynamic Conditions
Authors: Jonap K. , Vass A. , Vago A. 
Published: December 2007

Abstract
The gas industry (production, preparation, transportation) prevention of hydrate formation in pipelines using thermodynamic inhibitors (such as methanol) still represent a crucial problem from both technical and environmental points of view. Peculiar demand of the gas industry is represented by the fact that stability of gas flow and transportation must be extended towards lower temperature and higher-pressure range, which needs revised theoretical and practical approaches. Therefore, application of new innovative technologies and development of low-dosage chemicals, such as kinetic or anti-agglomerates inhibitors, are more than timely even today. The new and efficient compounds may retard hydrate formation for longer time than the residence time of the gas within the hydrate-prone section of pipelines and the low dosage inhibitors can also offer significant economic and environmental advantages compared to the traditional thermodynamic inhibitor.
To facilitate fast screening and selection of brand new inhibitors a model apparatus operating under dynamic conditions was developed. The sophisticated technique made the digital visualization and precise flow measurements possible at LT-HP conditions. The physical model system was fully computerized, all parameters were measured, processed and archived simultaneously.
Acrolein Application to Mitigate Biogenic Sulfides and Remediate Injection Well Damage in a Gas Plant Water Disposal System
Authors: Reed C. , Foshee J. , Penkala J. E. , Roberson M. 
Published: December 2007

Abstract
The unique and reactive chemistry of acrolein enables a 3-fold approach to oilfield problems stemming from sulfate reducing bacteria (SRB): 1) it is an effective biocide, 2) it scavenges H2S, and 3) it dissolves iron sulfide.
In this study, the utility of acrolein for remediation of problems with SRB and biogenic sulfides in a gas plant water disposal system at an Exxon Mobil facility in Mobile Bay, Alabama is presented. The disposal system, designed to handle produced water from offshore, process water from gas plant operations, and surface water drainage within the plant, was losing capacity due to iron sulfide fouling of the surface equipment and plugging of the disposal wells.
Bacterial monitoring indicated that SRB originating from the drain water had become established in the tanks and flowlines. These SRB were generating 8-10 ppm dissolved H2S that was ultimately responsible for the iron sulfide formation. The iron sulfide resulted in poor water quality (Millipore® rates=200-300 ml/5 min), tank fouling, filter plugging, injection line scaling, and loss of injectivity due to near well bore damage in the disposal wells.
The treatment design consisted of 1) initial remediation of injection wells by acrolein squeeze stimulations using a coiled tubing unit, 2) removal of iron sulfide pads from the tankage and iron sulfide build up in the disposal lines, and mitigation of SRB populations via batch treatments with acrolein, and 3) preventive maintenance using a continuous and batch treatment program with acrolein.
Immediately following squeeze treatment of the disposal wells, a 30% increase in capacity was observed. The topside treatment program has resulted in a 400 to 500% improvement in Millipore® rates, decreased levels of SRB, greater than 90% decrease in soluble H2S and a 65% decrease in filter replacements. Overall benefits of the program include acceptable injection rates and pressures and reduced operating costs through decreased filter changes, remedial expenses to maintain the disposal wells, and water trucking expenses.
Challenges and Insights in Optimizing Oil Production from Middle East Mega Karst Reservoirs
Authors: Trice R. 
Published: December 2007

Abstract
This paper is a summary of ongoing work to establish the impact of karst on optimizing oil production from carbonate reservoirs. The paper is based on a review of 44 Middle East carbonate reservoirs and is intended to convey preliminary findings. Key observations from this review are that karst reservoirs in the Middle East form one end-member of a continuum that includes, a) conventional layered reservoirs, b) fractured reservoirs, and c) karst reservoirs. It is also evident that many Middle East reservoirs are hybrid reservoirs having static and dynamic characteristics of all three end-members. In such instances the key challenge is to differentiate any karst components that may impact on achieving optimum oil production. Attempting to differentiate the karst contribution is complicated by the frequent occurrence of permeable tectonic fractures and faults. These lineaments contribute to permeability and production characteristics of many of the studied reservoirs, but because their characteristic flow properties are similar to that produced by karst drainage networks, karst drainage has the potential to be unrecognized. In an attempt to identify and isolate karst drainage system contribution to production, a first pass ‘quick look’ method has been developed by which carbonate reservoirs/fields can be ranked with the objective of assessing the degree that karst influences are present. The quick look method is intended to identify karst products, or the potential for karst products to be present, from which steps can then be undertaken to establish wheter a karst drainage system impacts optimum oil productivity.
Non-Upwind Versus Upwind Schemes for Hyperbolic Conservation Laws in Porous Media
Authors: Edwards M. G. 
Published: December 2007

Abstract
Standard reservoir simulation schemes employ upstream weighting approximations of the multi-phase/multi-component convective fluxes. The upstream definition depends upon the direction of the local phase velocities.
This paper presents novel convective flow approximation schemes in a non-upwind finite volume framework, which avoids both upwinding and characteristic decomposition, leading to a fundamental simplification of current methods. Stable lower order and higher order monotonicity preserving non-upwind approximations are developed.
The schemes are locally conservative and the formulation is consistent in IMPES mode (or sequentially implicit mode), with respect to sign change in wave velocity and mass balance.
Comparisons between velocity upwinding and the non-upwind schemes are presented for gravity segregated flow problems where waves undergo sign changes.
Fault and Fracture Corridors—How to Reduce the Structural Uncertainty for Reservoir Management Optimization
Authors: Bockel-Rebelle M. O. , Dabbour Y. , El Abd Salem S. , Vesseron M. , Silva F. P. 
Published: December 2007

AbstractThe occurrence of discontinuities such as faults, fractures or fracture corridors in the porous rock matrix usually has a strong impact on fluid flow and needs to be addressed carefully during the life cycle of the reservoirs.The major difficulty in characterizing the hydraulic properties of such systems frequently relates with our ability to integrate all the information in a meaningful way in order to derive the key factors constraining the development, intensity and role of the main fracture type in a given reservoir1.When the faults/fracture corridors act as baffles or barriers they may delineate compartments and blocks with differential drainage rates and variations in pore pressure. Where flow takes place in both the matrix and along/across the discontinuities, the flow paths can become very complex and the way the two systems interplay may even change with time or with injected/produced fluids.Likewise, the occurrence of faults identified from seismic or fractures brings some extra complexity to the strategies used for reservoir simulation. Issues like how to characterize the faults at different scales and to perform fault ranking and upscaling may have a strong impact on the way simulation results will match actual reservoir dynamics.