bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Comparison of Non-Aqueous and Aqueous Scale Inhibitor Treatments: Experimental and Modeling Studies
Authors: Guan H. , Sorbie K. S. , Mackay E. J. 
Published: December 2007

Abstract
This paper describes results from a series of comparative core floods and static compatibility tests examining the differences in laboratory test procedure, scale inhibitor (SI) returns and modeling approaches for non-aqueous and aqueous scale inhibitor treatments. Two types of non-aqueous system, one ethylene glycol based and two oil soluble products each containing penta-phosphonate scale inhibitors, were investigated. Detailed compatibility and injectivity tests were carried out before core flooding and special consideration was required in the treatment process due to their hydrophobic property. To understand the scale inhibitor transport and retention mechanisms for these non-aqueous products, comparisons were made with the relevant aqueous applications in terms of scale inhibitor return performance, flow back permeability, possible formation damage and wettability conditions which might account for any post-treatment changes. In addition, possible approaches to mathematically modeling these core floods were studied. This paper will focus on the application of a partitioning model in a standard reservoir simulator. An alternative two-phase mathematical model for such systems, which includes both inter-phase partitioning and adsorption has been described in detail in another recent publication.1
All core floods were performed using outcrop Clashach sandstone material rather than reservoir cores, and hence the advantages of deploying non-aqueous treatments over the conventional aqueous treatments would not be significant. However, the experimental and modeling results help to capture the features of these non-aqueous systems in an understandable way. Results confirmed the existence of complicated phase behavior during the core floods using two oil soluble products. Examination of the core after flooding using an environmental scanning electron microscope (ESEM) indicated decreased water wetness following the two oil soluble scale inhibitor treatments compared with the aqueous treatment. Numerical modeling results show that the behaviour of this system is most consistent with the assumption that the SI in the non-aqueous system is only slightly soluble in the oil phase during the oil post flush.
Accelerated Mechanism of Scale Deposition in UW Production Operation
Authors: Millan Juan Carlos , Dubey Sheila , Koot Wouter 
Published: December 2007

Abstract
An extensive study has been executed to understand the mechanism of calcite scale deposition occurring in the main heat exchanger at the MPP (main production platform) facilities at SVSA. The deposit necessitated a change out of the internals of the heat exchanger, which caused production deferment and capital expenditures.
The conclusion of this investigation was that the mechanism for accelerated calcite scale build-up in the HX heat exchanger is driven by the considerably high skin temperature (above 120 °C at normal heating conditions) in a high pH environment. This latter is caused by the triazine, which is part of the H2S scavenger package (used to remove H2S from some of the sour gas production), and by-products originating from the reaction of triazine (an amine) with H2S. The CaCO3 scaling tendencies and indices as calculated by scaling software (ScaleChem, StreamAnalyzer) predict the adverse impact of the high temperature and alkalinity conditions encountered in the heat exchanger.
Several technical options to mitigate the effects of the scavenger were considered from an economic and operational perspective. The most effective of the options was the injection of an appropriate scale inhibitor at a suitable dosage upstream of the heat exchanger.
Assessment of Scaling Tendency of Campos Basin Fields Based on the Characterization of Formation Waters
Authors: Bezerra Maria C.M. , Rosario Francisca F. , Rocha Anderson A. , Leonel Franca Fundação Padre , Sombra Cristiano L. 
Published: December 2007

Abstract
Campos basin reservoirs are responsible for an average oil production of 1.2 million bpd (83.5 % of Brazil's total production) with a forecast of 1.6 million bopd by the end of 2005.
cThis production comes from forty-one oilfields located between 50 to 140 km off the Brazilian coast (under water depths from 80 to 2.400 m) displaying a variety of reservoirs including Neocomian fractured basalts, Barremian coquinas, Early Albian calcarenites and late Albian to early Miocene siliciclastic turbidites (most frequently)(1).
Scaling risk for new fields is usually assessed in time as an input in the development phase of field projects. In order to guarantee a reliable formation water sample, from appraisal or development wells, a protocol was created based on data from twenty-six bottom-hole samplings. Correlations between produced fluid volume, porosity and permeability of the reservoir and the contamination degree were determined and used to define the minimum time of pumping necessary to have non contaminated samples.
This paper outlines the scaling tendency of the main fields from Campos Basin, based on the chemical composition of the waters and its association with the reservoir types. Scale risk of the fields is an important tool to be considered on the development phase project to support the decisions related to the appropriate technology to be adopted.
Experience with Pre-Emptive Squeeze Treatments on BP Magnus with Aqueous Based Scale Inhibitors
Authors: Strachan C. J. , Heath S. M. , White K. , Williams G. , Strong A. , Bell K. 
Published: December 2007

ABSTRACT
Barium sulphate scale is a major problem in the BP Magnus field, even at low water cuts (&lt;1%). In the late 1990’s BP Magnus adopted a policy of performing pre-emptive scale squeeze treatments on newly completed wells to prevent scale deposition and maintain well productivity on water breakthrough.
Squeezing dry and low water cut wells with aqueous inhibitor treatments can cause formation damage and result in changes in near well bore wettability. At this time, core flood studies carried out with conventional aqueous based inhibitor treatments indicated that it was possible to safely deploy these treatments in BP Magnus core material. A successful field trial was performed in 1998 since when it has been standard practice on the BP Magnus asset to pre-emptively treat dry and low water cut wells with aqueous inhibitor treatment packages.
Over the last few years a range of non-aqueous treatments technologies have been developed including oil miscible, emulsion and truly oil soluble scale inhibitors. Laboratory core flood studies have therefore been performed with these technologies, as they were developed to compare and contrast their performance to the use of aqueous based scale inhibitors.
This paper will detail a comparison of the core flood studies with both non-aqueous and aqueous based inhibitor treatments and will highlight that it is not always necessary to perform non-aqueous based treatments in dry and low water cut wells. An economic comparison of non-aqueous and aqueous based inhibitor treatments will be presented and, in addition, the paper will present the field experience gained to date with aqueous pre-emptive squeeze treatments in the BP Magnus field and outline the future scale management strategy for treating multi-lateral wells.
Why Does Scale Form in ASP Flood? How to Prevent from It?--A Case Study of the Technology and Application of Scaling Mechanism and Inhibition in ASP Flood Pilot Area of N-1DX Block in Daqing
Authors: Wang Yupu , Liu Junde , Liu Bing , Liu Yingping , Wang Hongxing , Chen Gang 
Published: December 2007

Abstract
ASP(alkali surfactant polymer) flood was initiated on March 15, 1997 in N-1DX block in Daqing oilfield; its main slug was completed on June 12, 1999. By September 23, 1998 pump malfunction occurred with a scale thickness of 1cm over in well bore. By the end of 1999, a serious scale was found in surface gathering and delivery system, with a 0.3cm of scale thickness found in single well pipes, gathering pipes as well as in heating furnace, this unfavorably affected current production.
In terms of this problem, we performed study of scale removal and inhibition. Analytical study over scale content, scale forming mechanism and regularity.Chemical agent study of scale inhibition.Study of physical scale prevention method, and we performed comparison test on different well respectively, using coated nickel, three layered compound coated pipes and ordinary pipes.We used hydro-electrical scale preventing unit, magnetic scale preventing unit in oil gathering pipes.
Through tests of the above methods in different wells, we obtained a satisfactory effect, the chemical agent method prolonged the pump check period from 30 days to 109 days; the coated pipe scaled slightly or didn't scale, and the scale was physically loosen. With these methods combined, scale prevention performed a good effect in well bores, single well pipes, oil gathering pipes and heaters. It ensured a conventional production in tested area. This paper presents the study of scale forming methods, the process of scale inhibition and the ideal effect we obtained.
Soap Sludges: Aggravating Factors and Mitigation Measures
Authors: Gallup Darrell L. , Star Jacquelyn 
Published: December 2007

Abstract
Greenish-brown soap sludge is formed in significant quantities during production of oil from the Serang field, offshore East Kalimantan, Indonesia. The sludge forms upon cooling of oil in subsea pipelines and onshore terminal storage tanks. This interfacial sludge is comprised of entrained free oil, water and solids, and is stabilized by an acyclic "metal carboxylate" soap. In the absence of fluid treatment, removal and disposal of the sludge is tedious, expensive, and represents significant un-recovered oil. The soap also adversely affects discharge water quality.
The sludge has been characterized to understand its formation mechanism, so that remedial actions can be taken to mitigate its deposition.1 A variety of analytical methods indicated that the "soap" emulsion consists of about 30% water, 50% oil, and 20% of C28 – C30 carboxylate salts in sodium form. The "soap" is stabilized by fatty acid-Na-HCO3 complexation, and results from the reaction of long chain fatty acids in oil with sodium bicarbonate-rich waters containing significant volatile fatty acids.
Laboratory and field tests have demonstrated that the sludge can be dissolved by low dosages of commercially available sludge dissolving agents containing combinations of acids. An acid demulsifier, consisting of acetic acid in an aromatic solvent mixture, and a non-acid demulsifier, consisting of ethoxylates and alcohol, have been injected into Serang produced fluid arriving at the onshore Santan terminal since August 2002. The demulsifiers have significantly reduced sludge deposition in oil storage tanks and water-handling facilities. In addition to "dissolving" sludge, incremental oil is recovered, which offsets chemical treatment and sludge disposal costs. Existing sludge is treated with chemicals and hot centrifuging to minimize waste and optimize oil recovery.
The Role of Electrolyte Simulation in Understanding the Failure of Shearwater Process Pipework
Authors: Webb Philip J. 
Published: December 2007

Abstract
Corrosion of metallic well and process materials can be caused by water that is co-produced with oil and gas. The corrosion processes involve electrochemical reactions that are dependent on the composition of the produced water. Variation of the produced water composition during oil and gas production can be investigated using electrolyte simulation tools that model the chemical reactions (chemical equilibria) that control the composition of the produced water. This paper describes how electrolyte simulation was used to investigate the failure of 2205 duplex stainless steel (UNS S31803) process pipework on the Shearwater installation, operated by Shell Exploration and Production, in the Central North Sea.
The failure of the 2205 duplex stainless steel (22Cr) involved stress corrosion cracking (SCC) initiated from both the outside and inside of the pipework. Cracks initiated from the outside were attributable to a known chloride SCC failure mode of 22Cr. The mechanism involved a high degree of evaporation of seawater on the pipework surface. However, the mechanism that initiated cracks from the inside was unusual because oxygen was not present. Electrolyte simulation tools were used to establish the chemical environment associated with the cracks initiated from the inside. It was demonstrated that evaporation of produced water, resulting from a 90 bar to 15 bar pressure reduction at ~136°C, had created brines with very high calcium and magnesium chloride concentrations. The resulting "exotic" brines had not been anticipated and were outside the range of environments for which the process materials had been qualified. Subsequent laboratory materials testing replicated the field failure in the presence of these brines.
This study highlights the need for materials selection to include rigorous evaluation of steady state and transient process environments using both electrolyte and hydrocarbon simulation tools. Special attention should be given to projects that apply materials and processing concepts in novel combinations. The failure illustrated that surface wetting of pipework can initiate corrosion failure even at very low water volume fraction (&lt; 0.5 vol%).
Heavy Oil Development: Summary of Sand Control and Well Completion Strategies Used with Multilateral Applications
Authors: Cavender Travis W. 
Published: December 2007

AbstractMultilateral drilling technology has been used in many heavy-oil developmental projects to achieve maximum reservoir exposure from a single surface location. The wellbore geometry and completion strategies for multilateral wells are planned and customized to fit the known reservoir characteristics and sand distribution qualities. Typically, heavy oil reserves are found in unconsolidated sandstone reservoirs that require some form of sand exclusion strategy across the reservoir as well as at the lateral mainbore junction interface. In heavy-oil sand, effective sand-control strategies must be carefully planned since one of the difficult problems to address in heavy-oil targets is their natural tendency to suspend formation solids, often referred to as Basic Solids and Water (BS&W) solids. An effective sand control strategy should allow these solids to be produced to surface and separated by the production facility. The remainder of the solids can be controlled, based on the sand-distribution qualities. If the formation sand is uniform, liner-only completions can be used for effective sand exclusion without sacrificing rate. If the formation sand is non-uniform, gravel packing will be required. For this reason, regardless of the well scenario, the gravel pack or liner only completion should allow BS&W solids to pass through and be produced to the surface.Most heavy oil development areas use artificial lift such as PCP and ESP pumps. All multilateral completion strategies must always consider the lift strategy, the ID requirements for pump deployment as well as necessary sand exclusion requirements for the pump.The paper examines successful multilateral completion strategies used in heavy-oil development projects in Canada, Trinidad and Venezuela. It will also explore new synergistic technologies that will impact future development strategies.
Steam Generation with High Tds Feedwater
Authors: Elias R. , Johnstone J. R. , Krause J. D. , Scanlan J. C. , Young W. W. 
Published: December 2007

Abstract
Generating steam with an oilfield water containing a high concentration of total dissolved solids (TDS) was tested in the North Midway Field, Kern County, California. Conventional zeolite and weak acid cation exchange softeners were used for feedwater treatment, and steam was generated in a small scale oilfield boiler. Feedwaters with TDS concentrations up to 22,500 parts per million were successfully softened to "zero" hardness levels and converted to 70% quality steam at 2300 psig. Results show that it is not necessary to have relatively fresh water for use in conventional oilfield steam generators. Furthermore, water treatment costs are economic.
Hydrocarbon-Steam Processes for Recovery of Bitumen from Oil Sands
Authors: Redford David A. , McKay Alex S. 
Published: December 2007

Abstract
The use of hydrocarbons together with steam was investigated as a means for improving recovery and other operating parameters in the interwell vertical steam-stimulation process for recovery of bitumen from oil sands.
A total of 42 experiments were conducted using a two-well, 18-inch diameter, three-dimensional elemental physical simulator operating at conditions close to those anticipated in the oil sands area of interest. The results of 20 of these experiments are presented.
A range of hydrocarbons from methane through ethane, propane, butane, pentane, natural gasoline, naphtha, to synthetic GCOS crude were investigated. The results of many of these experiments are presented and a number of observations and conclusions drawn. A proposed recovery process based on this work is presented.
The Effect of Dispersive Mixing on Scaling Laboratory Micellar Floods
Authors: Gash Bruce W. , Griffith T. David 
Published: December 2007

Abstract
For economic reasons, only a limited slug of a relatively expensive micellar fluid (followed by a polymer-water mobility bank) can be injected to displace oil with the current micellar flooding process. Once a micellar slug is injected, its composition does not remain the same; instead the composition changes as the slug propagates. Scaling the micellar flooding process can be thought of as using laboratory tests which consider the compositional changes that occur as the slug propagates to determine the minimum size slug necessary for effective displacement of oil throughout the swept portion of the reservoir.
Previous work has shown that surfactant retention is an important cause of compositional change which results in loss of displacement efficiency with a micellar slug. Dilution of a micellar slug (due to dispersive mixing) can be an equally important cause of poor displacement efficiency. In scaling a micellar flood, the dispersivity of the reservoir must be estimated from tracer tests. The ability of the micellar fluid to recover oil when it is diluted is a critical design criterion when reservoir dispersivity is large. Laboratory tests in short reservoir cores can be appropriate to simulate performance in a reservoir when the reservoir dispersivity is greater than the dispersivity of the reservoir cores. Berea sandstone which has very low dispersivity is not an appropriate porous medium in which to study the scaling of a micellar flood.
Steamflood Performance in the Kern River Field
Authors: Greaser Gary R. , Shore R. A. 
Published: December 2007

Abstract
The Kern River Field is a large, shallow, heavy oil reservoir located five miles northeast of Bakersfield, California. Both reservoir and fluid characteristics are very favorable for thermal recovery methods. The unconsolidated oil sands exhibit high permeabilities of 1-5 darcies (1-5 μm2) and porosities of 28-33%. Reservoir pressure is low, averaging 100 psig (690 kPa). Oil viscosities average 4000 cp (4 Pa.s) at reservoir temperature and drastically reduce at elevated temperatures.
Previous articles1,2,3,4 have been published concerning steamflood pilot design and behavior in the Kern River Field. This paper updates previous articles with a review of 263 steamflood patterns started in 1970 and 1971. The effects of sand thickness, completion interval and heat injection rates on steamflood recovery will be analyzed. Effective project evaluation through the use of temperature observation wells, coring, casing blow measurement and production from wells completed solely in the steamflood interval is emphasized. Problems of evaluating steamflood performance in a multi-zone reservoir are discussed and two field tests for improvement of steamflood sweep efficiency are also presented.
Scaling of Non-Equilibrium Phenomena in Surfactant Flooding
Authors: Hirasaki George J. 
Published: December 2007

Abstract
Laboratory core floods are not conducted with the same time scale as field projects. Consequently, it is possible for non-equilibrium phenomena to be significant in laboratory core floods but be insignificant in field projects. The purpose of this paper is to analyze some non-equilibrium phenomena to determine scaling groups and qualitative behavior. Scaling groups were estimated for diffusion controlling and sorption rate controlling mass transfer. Further measurements are needed to quantify interfacial resistance controlling mass transfer and intraphase rate dependent phenomena.
New Approach to Log Simulation in a Horizontal Drain – Tambora Geosteering Project-Balikpapan, Indonesia
Authors: Le Turdu Caroline , Bandyopadhyay Indrajit , Ruelland Philippe , Grivot Patrick 
Published: December 2007

Abstract
This paper is presenting a workflow applied successfully during the summer 2003 on the Tambora Field in East Kalimantan, Indonesia. The combination of a modeler (PETREL) together with a geosteering application (INFORM) in real time was a new approach to generate scenarios of tool response to formation changes in a horizontal drain. The aim of this paper is to share our experience and describe the workflow, which came as a real help to geosteering as events can be anticipated with a certain reaction time.
The first steps of the project consisted in preparing the 3D model, incorporating all geophysical and geological information to get a complete overview of the distribution of the petrophysical properties through the field. Once the drilling started and before entering the reservoir, the model was updated with the new picks and eventually new horizon interpretation. The GR and Resistivities were modelled and a set of synthetic logs along the well trajectory was exported from the 3D modeler into a geosteering application. Then a series of simulations of expected logs were run giving the asset team a set of possible scenarios to foresee possible situations during drilling and prepare contingency plans beforehand thereby enabling efficient geosteering.
The geomodeler enabled to build a 3D Earth model, which can be easily updated with real time data: it was also seen as a good communication tool.
A New Method for Analytical Modelling of Chemical Flooding
Authors: Shapiro A. A. , Bedrikovetsky P. G. , Pires A. P. 
Published: December 2007

Abstract
Compositional models with adsorption describe polymer/surfactant flooding with varying salinity. It is shown that the concentration "part" of the solution for 1-D multicomponent polymer/surfactant flooding is completely defined by adsorption isotherms and is independent of relative permeabilities and phase viscosities. We introduce potential coordinates allowing for the compositional model splitting into a thermodynamics auxiliary system and one transport equation. The number of auxiliary equations is less than the number of equations of the compositional model by one. Explicit projection and lifting procedures are derived. The splitting is valid for either self-similar continuous injection problems or non-self-similar slug injection problems.
With respect to 3-D flows, splitting takes place only for the case of constant total mobility. For the general case of the total mobility variation, mixing between fluids that enter different streamlines occurs, and splitting does not happen any more.