bluuebunny/crossref_metadata_2025_split huggingface dataset:
Large Scale Laboratory Investigation of Corrosion Inhibitor Containing Emulsion Placement in Wells
Authors: Sanghvi Gautam J. , Garcia David A. , Civan Faruk , Shaw Thomas M. , Campbell Samuel E. , Bartrip Keith A. 
Published: December 2007

AbstractAccurate placement of emulsions containing formulated inhibitors in the casing-tubing annulus can provide more effective and long term well treatment than the standard batch methods. This paper presents the results of experimental investigation and correlation of experimental data based on a large-scale model well constructed to simulate flow within the typical well annulus. The wellhead and bottom hole assemblies were designed to closely simulate those found in producing oil and gas fields.Various chemicals were injected at the wellhead to flow through the annulus, to determine the role of viscosity, density, and surface tension, which were then followed by brine flush. The flow of emulsion and flush through the annulus was recorded at fixed positions and with mobile cameras. The observation and identification of the flow patterns during the treatment was made. A set of pins was inserted into the casing wall. This allowed the measurement of thickness of the emulsion coating the annular surface. The surface area coated by the emulsion was traced and measured. Downhole emulsion delivery was thus determined by performing the emulsion material balance. The amount of emulsion retained in the system is based on deposited chemical thickness, coated surface area and concentration of chemical in the annular fluids after the tests.The results were correlated using dimensionless groups to allow extrapolation to well depths encountered in a typical oilfield production. The effectiveness of emulsion delivery and the flow patterns in the annulus were determined to strongly depend on the application type and conditions.
Barium Sulphate Inhibition in Subsea Systems – The Impact of Cold Seabed Temperatures on the Performance of Generically Different Scale Inhibitor Species
Authors: Laing N. , Graham G. M. , Dyer S. J. 
Published: December 2007

Abstract
Inorganic precipitates (scales) are one of the major flow assurance concerns in offshore oil and gas production, and lead to significant reductions in productivity and costly workovers if allowed to form uncontrolled. Scale prevention by the use of chemical inhibitors, applied either by continual injection or by squeeze treatment into the near wellbore formation, has generally been regarded as the most cost effective solution to the problem. The increased development of subsea satellite production brings with it a number of additional challenges to the chemical control of inorganic scale. The requirement to control scale at low seabed temperatures (4 - 5°C) over long residence times presents a particular challenge.
This paper examines the performance of three generically different scale inhibitor species including a polyvinyl sulphonate (PVS), a phosphino polycarboxylate (PPCA) and a penta phosphonate (DETPMP) under typical North Sea Scaling conditions. The relative performance of the different inhibitor species against Barium Sulphate scale is compared at temperatures between 5°C and 5°C and up to 22 hours residence times.
Results show that the performance of different inhibitors are significantly affected and to different degrees as a function of temperature, and that this is not simply related to changes in supersaturation against barium sulphate precipitation. The performance of the phosphonate species DETPMP is significantly reduced at lower temperatures and this is related to reduced adsorption at the barium sulphate surface. However the performance of the PVS is significantly improved, indicating that such species offer the potential for improved scale control at lower seabed temperatures. PPCA is only marginally affected by reduced temperatures in a manner more consistent with the increased supersaturation against barium sulphate.
Investigation of Wettability Alteration Following Scale Inhibitor Adsorption onto Carbonate and Clastic Reservoir Core Material – Static Tests and ESEM Studies
Authors: Guan H. , Graham G. M. , Juhász A. 
Published: December 2007

Abstract
In this paper, we make an assessment and comparison of scale inhibitor/rock interactions onto carbonate (calcium carbonate and dolomite) and clay-rich (illite-rich and kaolinite-rich) core materials. This is compared using both non-solvent cleaned and solvent cleaned (increased water wetness) reservoir chips of the same core material. In order to investigate the wettability alteration following the interaction with scale inhibitor solutions, ESEM studies were carried out on the pre- and post treatment reservoir chips.
The interaction of two generic scale inhibitor chemicals penta-phosphonate (DETPMP) and phosphino-polycarboxylic acid (PPCA) with various un-cleaned and solvent-cleaned core substrates at pH 2 and pH 5.5 have been examined under static conditions. The bulk differences in the inhibitor-rock interactions have been assessed by the comparison of cation (Ca, Mg) and scale inhibitor (SI) concentrations of pre- and post treatment core chips. ESEM observations and EDAX analysis of the pre- and post treatment core chips have then allowed for the investigation of wettability alteration following the interaction with various scale inhibitor solutions.
In summary, quite distinct inhibitor/rock interactions and wettability alterations are observed at different mineral surfaces. Under certain conditions, excessive surface precipitate of pseudo scale (inhibitor/calcium complex) can occur as a result of mineral dissolution and consequential localized increase in pH and cation concentration. In addition, the adsorption/precipitation of SI onto certain minerals under specific conditions have been found to reverse the original wettability state of the reservoir chips. The results therefore help to explain relative permeability issues associated with scale inhibitor treatments both in core flood experiments and field treatments. Moreover, the hot solvent cleaning process has made the initial mineral surface more water wet.
Boosting the Heating Capacity of Oil-Production Bundles Using Drag-Reducing Surfactants
Authors: Sletfjerding E. , Gladsø A. , Elsborg S. , Oskarsson H. 
Published: December 2007

Abstract
Insulated and heated pipe bundles are frequently used in sub sea oil production systems to avoid low oil temperatures. To boost the heating capacity of the 10 km long pipe bundle from the Gullfaks South field in the North Sea, a surfactant based DRA was developed. The DRA was injected in the 20 km long heating medium loop in July 2001, and after over 12 months of operation the DRA gives over 50 % increase in the heating medium flow rate. The surfactant has effectively reduced the pressure drop in the heating medium circulation loop resulting in an increase in the flow rate and in the bundle heating capacity.
Development of a Set Retarder for Foamed Cement Applications
Authors: Chatterji J. , Crook R. J. , Lebo S. E. , Resch S. L. 
Published: December 2007

Abstract
Due to a recent resurgence in foamed cement utilization, there is a need for an additive that can provide adequate set retardation without affecting the foam characteristics of the cement system. This paper details the development of a foamed cement retarder comprising a blend of lignosulfonate, kraft lignin and a pentose sugar. Laboratory studies have shown that the performance of this product exceeds that of conventional set retarders with regard to maintaining the stability of the foamed cement system. This set retarder can also function in non-foamed applications. Several wells have been successfully completed using this new technology and case histories will be provided.
New Opportunities for the Drilling Industry Through Innovative Emulsifier Chemistry
Authors: Patel Arvind , Ali Syed 
Published: December 2007

Abstract
As the drilling industry operates in more stringent environmental constraints and conservative economical environment, the industry is poised to take advantage of innovative emulsifiers for new opportunities in solving the environmental problems and offer economical advantages over conventional invert emulsion drilling fluids. We have developed various innovative invert emulsion drilling fluids using novel emulsifiers. These systems provide a quantum leap in new drilling fluid technology in solving environmental problems while offering economical advantages over conventional invert emulsion drilling fluids.
Since, the inception of invert emulsion drilling fluids decades ago, emulsifier technology for these systems has not advanced much. The focal points in development in past history have been in base fluids, O/W ratios and some in weight materials, however very little has been changed in emulsifier chemistry. Only step-changes in technology have been achieved with changes in base-fluids and other parameters of invert emulsion drilling fluids. It is time to move on. Using innovative emulsifier chemistry has produced novel invert emulsion fluids, which address the environmental as well as performance and cost-related issues in drilling operations.
This paper discusses the systematic design, development and testing of novel emulsifiers for innovative invert emulsion drilling fluids. The overall impact of manipulation of emulsifier chemistry in invert emulsion drilling fluids to meet the environmental and functional requirements of drilling operation is presented. The formulations and applications of lime-free high temperature invert emulsion drilling fluid, negative alkalinity ester-based fluid, and reversible invert emulsion drilling fluids in laboratory experiments as well as field trials are highlighted.
Deployment of Emulsified Scale – Inhibitor Squeeze to control Sulphate/Carbonate Scales within Subsea Facilities in the North Sea Basin
Authors: Jordan M. M. , Murray F. , Kelly A. , Stevens K. 
Published: December 2007

Abstract
This paper presents laboratory/field results and lessons learned from a North Sea field where a novel emulsified scale inhibitor was deployed via bullhead squeeze treatments in four low water cut, sand screened wells. The field is a subsea development within the UK sector of the North Sea. These were the first squeeze treatments to be performed on the field.
The remote location of the production wells relative to the production vessel and their high production levels meant that scale management was critical to the effective recovery of hydrocarbon from the field. The risk of scale formation even at low water cut was deemed sufficiency high for a scale inhibitor squeeze application to be applied.
The decision to use emulsified scale inhibitor for treating such low water cut wells was arrived at after an extensive series of laboratory tests including formation damage coreflood studies and assessment of chemical retention. The risk of fines mobilisation when deploying water based chemicals in low water cut, poorly consolidated reservoir will be outlined.
The challenges with the deployment of the chemical package via a diving support vessel (DSV) and gas lift line will also be outlined along with the performance of the wells following the treatment and the effectiveness of this scale control method.
This paper will outline in detail the particular issues associated with chemical injection to a subsea facility, many of which are currently being developed in the Gulf of Mexico and is a good example of lessons learned and sharing best practice from another oil basin.
The Impact of Dissolved Iron on the Performance of Scale Inhibitors Under Carbonate Scaling Conditions
Authors: Graham G. M. , Stalker R. , McIntosh R. 
Published: December 2007

Abstract
The laboratory determination of scale inhibitor (SI) performance under field specific conditions using dynamic or static scale inhibitor tests provides an important method for determining minimum inhibitor concentrations (MIC's) for the inhibition of scale growth. This paper will discuss the ability of small amounts of ferrous iron to dramatically reduce the ability of SI's to inhibit calcium carbonate scale formation under dynamic laboratory test conditions. It has been previously reported that the presence of ferrous ions has an inhibiting effect on calcium carbonate formation under dynamic test conditions, which was confirmed for the brine systems used in this study. However, despite the somewhat milder scaling regime in the presence of ferrous ions, addition of Fe2+ ions to test brines caused the observed MIC's of typical scale inhibitor chemicals to increase more than one hundred fold when tested against calcium carbonate scale. A much less dramatic reduction in SI performance in the presence of ferrous ions was observed for barium sulfate scale formation under dynamic test conditions.
Such interference in inhibitor performance can have major implications for the field application of scale inhibitor chemicals, leading to unexpected decline in production. The presence of ferrous ions has been shown to adversely affect scale inhibition of a number of different classes of SI chemicals, including poly(vinylsulphonate) (PVS) which has previously been reported as being iron-tolerant. This paper will describe the results of laboratory studies into this phenomenon, in which the nature and scope of the interference were investigated.
Scale Formation And Prevention In The Presence Of Hydrate Inhibitors
Authors: Tomson M. B. , Kan A. T. , Fu G. , Al-Thubaiti M. 
Published: December 2007

Abstract
Hydrate formation can be a serious problem in many gas production systems. Large volumes of hydrate inhibitors (e.g., methanol, ethanol, ethylene glycol, and triethylene glycol as cosolvent) are often added to control hydrate formation. Such practice has an adverse effect on scale formation since the mineral salts are generally less soluble in the cosolvent. Due to production from reservoirs oilfield brines are often close to saturation as they enter a well, and even a small amount of added methanol, ethanol, etc., is often sufficient to induce various minerals to precipitate. The scaling tendency of sparingly soluble mineral salts, e.g., calcite and barite, in methanol/brine and ethanol/brine solutions is observed to be orders of magnitude larger than in the brine alone. Halite scaling is also severely affected in the presence of methanol or ethanol. Ethylene glycol and triethylene glycol have a lesser adverse effect on mineral salt scaling tendency. There is no accepted methodology to correlate the effects of hydrate inhibitors on scale formation as there is for electrolytes. Similarly, the effect of hydrate inhibitor on scale inhibition with common inhibitors is not well known. In this paper, a semi-empirical approach is proposed to correlate the effect of hydrate inhibitors on scale formation and inhibition from experimental solubility measurements of halite, barite, gypsum, calcite and carbonate equilibrium chemistry. The ion-cosolvent activity coefficients can be used directly in any solution speciation code to evaluate the effect of cosolvent on mineral scale formation. The validity of the equation has been tested between 4-50 °C and 1-6 M ionic strength. Working equations that can be used in gas and oil production to calculate the effect of cosolvents on scale formation will be presented. Such equations have been incorporated into ScaleSoftPitzer V.4.0. ScaleSoftPitzer™ is a Microsoft™ Excel™ based program to predict scale tendency, specifically written for the oil and gas production systems. Details of using ScaleSoftPitzer V.4.0 to predict hydrate inhibitor induced scale formation and case studies will be presented. Initial tests of scale inhibitor efficiency in methanol will also be presented.
Effect of Rock Type and Acidizing Additives on Acid Reaction Rates Using the Rotating Disk Instrument
Authors: Taylor K. C. , Al-Ghamdi A. H. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
This work uses a rotating disk instrument to measure dissolution rates of both calcite and dolomite rock samples. Results of more than 60 experiments are reported in this paper. The effect of common acidizing additives on the acid dissolution rate is measured for different acids containing quaternary amines, polymer, surfactant, mutual solvent, iron chelating additive, and dissolved iron.Measurements are made at 23 and 50 °C for calcite marble and dolomite marble samples.
Marble samples from Turkey, Greece and Italy were analyzed to find suitable reference materials.Marble composed of 100% calcite (calcite marble) as well as 91% dolomite (dolomite marble) was used and compared very well with previously published results.Results of acid dissolution rates with common acidizing additives showed significant differences. 1.5 vol% cationic acrylamide polymer decreased the calcite and dolomite dissolution rates significantly. At 1000 rpm the calcite dissolution rate with 1.5 vol% polymer and 0.1N HCl had a value that was 11.4% of the value measured with 0.1N HCl alone.Polymer changed the acid-rock reaction from mass transfer limited to surface reaction limited with both calcite and dolomite. This is a surface effect possibly due to polymer adsorption.10 vol% mutual solvent increased the acid dissolution rate by 9% for calcite and by up to 29% for dolomite.5,000 mg/L iron (III) resulted in surface deposition of iron (III) hydroxide. At low rotational speeds, this surface layer had an inhibiting effect on dissolution rate for both calcite and dolomite.2 vol% corrosion inhibitor decreased the calcite dissolution rate by approximately 9%.Citric acid at 12 g/L decreased the dissolution rate of calcite by an average of 9%, possibly due to the formation of calcium citrate at the surface.0.2 vol% nonionic surfactant had no significant effect on acid dissolution rate of calcite.
Prediction and Scaleup of Waxy Oil Restart Behavior
Authors: Borghi G. -P. , Correra S. , Merlini M. , Carniani C. 
Published: December 2007

Abstract
A major concern in the design of offshore pipelines is flow restart of waxy oil after a planned or emergency shut-down. As the offshore oil industry encounters increasingly challenging production environments, such as in deepwater or marginal fields, more accurate restart predictions are a requirement for reducing CAPEX and guaranteeing flow assurance. The present state-of-the-art does not generally provide reliable predictions of the pressure required to restart flow in a gelled pipeline; laboratory measurements tend to overestimate the restart pressure, so that empirical factors are used to scale the laboratory data to field conditions. Based on a series of experimental measurements carried out in a upgraded model pipeline, our analysis suggests that compressibility and the appearance of a solid-like fracture at the front of the propagating pressure wave have to be taken into account in order to better model the cold restart process.
A Thermochemical Process for Wax Damage Removal
Authors: Rocha Nelson O. , Khalil Carlos N. , Leite Lúcia C.F. , Bastos Roberto M. 
Published: December 2007

Abstract
Relevant declines in oil production on several Reconcavo Basin wells (NE Brazil) have been observed as a result of wax deposition phenomena. Evidences indicate several points of wax obstruction, such as: reservoir rock, perforations, casing annulus, tubing and production lines.
The process consists on the injection of an emulsion formed by an aqueous solution containing nitrogenated salts, an organic non-polar solvent and a viscoelastic polymer. When the mixture is placed in the annulus, a strongly exothermic chemical reaction occurs, generating a high quality stable foam. The penetration radius of the foam into the porous media is enough to assure sufficient wax removal and induce immediate production enhancement. During well depressurizing, nitrogen gas, an aqueous saline phase and an organic mixture containing wax and the solvent are recovered. All the reaction products are environmental friendly.
This paper presents lab and field results of this workover method based on in situ thermal generation of foam. Lab studies include foam formulation optimization aiming maximum wax deposit removal in several reservoir conditions. Field implementation includes the analysis of production enhancement in 10 wells in the area where the technique has been applied.
Low-Dosage Hydrate Inhibitors (LDHIs): Reducing Costs in Existing Systems and Designing for the Future
Authors: Frostman L. M. , Thieu V. , Crosby D. L. , Downs H. H. 
Published: December 2007

Abstract
Hydrates remain a significant flow assurance issue in nearly every Deepwater development. Traditional hydrate control methods of insulation and/or thermodynamic chemical inhibition may not provide the desired level of hydrate protection at an economic price. Low-Dosage Hydrate Inhibitors (LDHIs) are a proven technology to control hydrates in numerous applications and are instrumental in reducing the total cost of operations (TCO). In particular, LDHIs offer solutions to existing problems such as unexpected water breakthrough, undersized methanol injection capacity, and high-volume methanol transportation / storage limitations. As an added benefit, it is possible to co-formulate LDHIs with other production chemicals, such as paraffin and corrosion inhibitors, and thus minimize the number of chemical injection lines. While the benefits to existing developments are appreciable, the true potential of this technology lies in the reduced capital expenditures (Cap Ex) required for systems designed specifically for LDHIs. Potential savings include, smaller umbilical line diameters, the elimination of a methanol wash and recovery operation, fewer umbilical lines, smaller / lighter storage capacity, and smaller pumps.
Application of Novel Diversion Acidizing Techniques To Improve Gas Production in Heterogeneous Formation
Authors: Wang Xugang , Zou Honglan , Tian Jun , Zhang Fuxiang , Cheng Xingsheng , Li Suzhen 
Published: December 2007

Abstract
The aims of this study were to design a novel diversion acidizing stimulation treatment to remove formation damage and enhance gas production in a recently exploring ultradeep heterogeneous sandstone gas fields in TARIM, while avoiding formation collapse.
Although foam can be used to divert acid from the chief zones to the damaged zones, it is not available in this kind of ultradeep abnormally high pressure gas field and an additional handling equipment is required. In this paper a new diversion technique from both laboratory testing and field monitoring is discussed in detail. Laboratory testing conducted in a dual-core flow apparatus showed excellent diversion from a high-permeability formation to a low permeability one by using viscosity system. Field case histories in the heterogeneous gas formation in TARIM over past three years are presented. The field cases histories show the success of diversion acid technique and the improvement of gas production significantly.