bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Naphthenate Scale and Soap Emulsion Management
Authors: Runham Gerard , Smith Colin
Published: April 2009

Naphthenate scales and carboxylate soap emulsions have become increasingly evident issues as more marginal crudes are sourced and through greater awareness. These issues are not new but the potential severity and increased occurrence highlights the need for successful management and the importance to field development and expansion. This paper provides a comprehensive and up-to-date resource for successful management of naphthenate/carboxylate issues. The paper is aimed at development projects, during flow assurance assessments as well as existing operations trying to manage naphthenate/carboxylate issues, and attempts to bring together all available information to provide a holistic approach to management.

There is a number of different control approaches published in the literature and in the author's experience. No definitive solution has been identified but this paper provides a review of varying strategies for mitigation that if appreciated early or even later in production life, can result in successful management. Previously, operational problems caused by naphthenate/carboxylate have occurred in production facilities, which then require remedial efforts and significant chemical treatment. As more knowledge is available, effort has been applied to the development stage through new innovative system designs. These combine identification and understanding with process design, operational practices, chemical treatment and remedial efforts. No particular approach is more effective but should be tailored to the development and how the problem manifests itself. Equally there is no ‘magic-bullet’ currently to these problems but nevertheless, with good understanding and considered application of different approaches, these naphthenate/carboxylate problems can be successfully managed.
Experimental Methodology to Evaluate DRA: Effect of Water Content and Waxes on Their Efficiency
Authors: Henaut I. , Darbouret M. , Palermo T. , Glenat P. , Hurtevent C.
Published: April 2009

Drag reducing agents are used to reduce significantly the frictional pressure loss under turbulent flow conditions, allowing a substantial increase in pipeline capacity. Their performance is known to depend on their own characteristics (molecular weight, structure, chemical composition) and on external parameters such as turbulence intensity, oil viscosity, etc. The mechanism by which DRAs interfere with turbulence is not fully understood and drag reduction is not easy to predict. Laboratory tests are still required to quantify the potential efficiency of these additives. This paper reports on an original experimental methodology based on the combined use of a classical rheometer and a laboratory loop offering a large range of experimental conditions in terms of temperature, pressure, flow rates and cooling rates. Different commercial oil soluble DRAs have been tested on various fluids including a paraffinic crude oil. The experimental results have shown that either the presence of waxy crystals or emulsified water droplets can alter the DRA efficiency, while they are not affected by waxy deposits or low temperature.
Barite Nucleation and Inhibition at 0-200°C, With and Without Hydrate Inhibitors
Authors: Fan Chunfang , Kan Amy T. , Tomson Mason B.
Published: April 2009

This work is the first detailed and reliable study of barite nucleation kinetics in the presence and absence of scale inhibitors at 0-200°C. In this study, we developed an apparatus to study the nucleation kinetics of barite scale formation at high temperature in the presence and absence of scale inhibitors by monitoring pressure change over a micrometer sized in-line filter, which has been proved to be an easy and accurate method to study mineral scale nucleation kinetics at high temperature conditions. Additionally, we investigated the nucleation kinetics of barite at 0-25°C with and without hydrate inhibitors. By using this newly developed "pressure" method, we successfully measured the nucleation kinetics of barite in 1M NaCl solutions at a temperature range from 100-200°C and at various supersaturation conditions. We also evaluated the inhibition efficiency of barite precipitation at this very high temperature range. Based on the experimental results, the relationship of precipitation kinetics of barite as a function of temperature and saturation index was established. The inhibition efficiency of phosphonate inhibitor (BHPMP) on barite precipitation has been evaluated over the same range of condition. Results of this study have been incorporated into the scale prediction software, ScaleSoftPitzer.
Quantitative Evaluation of Calcium Sulfate Precipitation Kinetics in the Presence and Absence of Scale Inhibitors
Authors: Kan Amy T. , Fu Gongmin , Fan Chunfang , Tomson Mason B. , Shen Dong
Published: April 2009

In this study, the nucleation kinetics of calcium sulfate scale formation in the presence and absence of scale inhibitors has been studied. The nucleation kinetics of calcium sulfates in 0 – 3.2 M NaCl solution was measured from 0 – 200 °C at various supersaturation conditions (SI = 0-1.3). The phase behavior of these various calcium sulfate phases were monitored by X ray diffraction. The inhibition study was done by evaluating the inhibition efficiency of calcium sulfate precipitation at the same supersaturation and temperature ranges as the nucleation study. Several polyphosphonate, polymeric and green inhibitors were found to be effective inhibitors. The study has shown that calcium sulfate scales are very difficult to inhibit at SI > 1. Calcium sulfate scale is most effectively inhibited by HDTMP (hexamethylenediamine tetra(methylene phosphonic acid)) if the saturation index is below ~1.0. In addition, a semi-quantitative model to predict precipitation kinetics of calcium sulfate as a function of temperature, pH, saturation index and HDTMP concentration was established with experimental results from this study. The effect of methanol and methylene glycol on calcium sulfate precipitation kinetics and inhibition is also presented.
Chemistry of Injection Water and its Impact on Oil Recovery in Carbonate and Clastic Formations
Authors: Alotaibi M. B. , Nasr-El-Din H. A.
Published: April 2009

Waterflooding has been used for many decades as a way of recovering more oil. Historically, the salinity of the injection water has not been regarded as a key variable in determining the amount of oil recovered. Crude oil/water/rock chemical interactions can lead to large variations in the microscopic displacement efficiency of waterflood. There is increasing evidence, as reported in the literature, that injecting low salinity brines has a significant impact on the amount of oil displaced, but the exact mechanism by which this occurs is an unsettled issue. The main objective of this paper is to determine the effects, advantages, and practicalities of using low salinity waterflood to displace more oil in both carbonates and clastic formations. Another objective is to understand the main mechanisms in low salinity waterflood, and to determine the effects of salinity level on oil recovery.

An extensive literature review is assembled about fluid/rock interactions, wettability alteration, clay hydration, and multi-component ion exchange (MIE), and waterflood experiments using coreflood setup. Seawater injection in carbonate formations has important effect on oil recovery, especially in fractures. The recovery mechanism is completely different in carbonate than in sandstone formations, due to different rock mineralogy, brine concentration and chemistry. Salt content in connate water also plays a role in increasing oil recovery, especially when decreasing the brine salinity. The effect of high, medium, and low salinity brines on lowering the oil-water interfacial tension and/or alter the wettability characteristics of the reservoir rock is discussed. The effects of various salinity brines on reservoir rocks during waterflooding are necessary to recover more oil and that at the end will increase oil recovery.
Remediation of Naphthenate Stable Emulsion for Malaysian Oilfields
Authors: Salleh Intan Khalida , Nadeem Muhammad , Aziz Khairul Mustaqim A. , Alwi Noraliza , Hamid Pauziyah A. , Azhan Arif
Published: April 2009

Crude oil production from various fields contains large amounts of naphthenic and carboxylic acids. Combination of formation and injection water with these acids has resulted in the production of stable viscous emulsion which affects oil production to a large extent. Due to the unique properties of different crudes, injection and formation waters a better understanding of the chemistry of the naphthenic acids is of great interest. Interaction of naphthenic acids in crude oil with metal ions such as calcium and sodium leads to the formation of naphthenates. Moreover, the release of CO2 from the crude oil at sufficiently low pressures leads to a corresponding increase in pH which then leads to the formation of soaps. The behavior of naphthenates ranges from soft to hard emulsion which depends on the cation composition of the brine and other contributing factors.

This study investigates the effects of a range of parameters on the Naphthenate emulsion formation, including naphthenic acid type, composition of the brine, pH, etc. A pseudo model of synthetic naphthenic acids using commercial mixtures and various types of crude oil and naphthenic acid was utilized to investigate emulsion stability and viscosity. It was concluded that brine chemistry and pH play a major role in the stability and viscosity of the emulsion. Slight variation in the pH with controlled brine composition accelerates the demulsification process.
The Application of Bioassays for Evaluating In-Situ Biocide Efficiency in Offshore Oil Production in the North Sea
Authors: Hansen Lars Hvejsel , Larsen Jan , Jensen Michael , Thomsen Uffe Sognstrup , Sørensen Ketil , Lundgaard Thomas , Skovhus Torben Lund
Published: April 2009

Microbial activity has a severe impact on corrosion of oil production facilities and reservoir souring. Bacterial growth and metabolic products significantly aggravating the corrosion of pipelines, manifolds, and separators which increases the risk of system failure. Microbiologically influenced corrosion (MIC) is caused by the turnover of hydrogen, sulfur and organic carbon driven by sulfate-reducing bacteria (SRB), sulfate-reducing Archaea (SRA) and methanogens.

One important risk management tool is biocide dosage to control microbial activity in offshore oil production systems. To obtain a cost-efficient biocide treatment strategy it is important to determine biocide efficiency using microbiological assays (bioassays) that comprise quantitative measures of:

Bacterial growth. Activity of specific bacterial groups related to MIC and souring. Accumulation rates of carbon dioxide, sulfide and methane.

The bioassays presented in this paper investigate microbial activity in produced waters from an offshore platform where different biocides were tested. Based on molecular microbiology methods (MMM) it was evident that bacterial growth occurred in production water without addition of biocide at growth rates up to 0.46 1/d. Furthermore, active growth of both SRB and Archaea indicated that microorganisms that may be involved in corrosion processes were active in cell numbers of 105 cells/mL. Concurrently, depletion of sulfate and accumulation of total inorganic carbon, sulfide, and methane due to microbial activity was measured and maximum rates were used in combination with MMM to evaluate activity in bioassays with and without biocide. The results showed that addition of biocide in both injection and production waters decrease cell numbers and metabolic activity of SRB and methanogens.

In general bioassay results can be used to evaluate the efficiency of biocides and nitrate at different dosage concentrations. The bioassays are most valuable when implemented in a risk assessment model for MIC and souring of oilfield reservoirs.
New Method for Scale Inhibitor Testing
Authors: Halvorsen Erling Notto , Halvorsen Anne Marie Koren , Reiersølmoen Kristin , Andersen Tore Roberg , Biørnstad Cecilie
Published: April 2009

During qualification of scale inhibitors for the Ormen Lange project, it was discovered that the dynamic tube blocking (DTB) test could not simulate the scaling conditions good enough for gas/condensate subsea fields which will be using pH stabilised MEG for hydrate control.

The pH stabilizer in the lean MEG will be present mainly as carbonate and the pH is >10. After mixing with the well fluids the pH will be reduced to ~7. At the subsea mixing point the carbonate will react with CO2 gas and produce bicarbonate. This process could not be simulated with the DTB equipment since it did not allow CO2 gas to be present at the mixing point and the synthetic formation water could not dissolve enough CO2. The result will be too high pH and too high scaling potential. Presence of particles in the lean and rich MEG is also important for the efficiency of scale inhibitors, which in some cases can be difficult to include in tube blocking tests.

A new test method has been developed that simulates the mixing point subsea and the pipeline downstream the MEG injection point. Cold lean MEG with particles and warm formation water is mixed and flow down a warm glass wall in a double walled cell purged with CO2 or a mix of CO2 and N2 to achieve the correct CO2 partial pressure and temperature. Then the mix of MEG, formation water and gas is pumped through a glass and/or steel coil. Examination of the glass and steel coils are done visually by the eye and by SEM, respectively.

The new test method has been tested and has been used to qualify a scale inhibitor for a subsea development. The use of glass coils showed that the method not only shows presence of scaling if the inhibitors does not work satisfactory, but gunking (in this case separation of components which stics to the surface stemming from scale and/or corrosion inhibitor caused by incompatibility) has also been observed by this method.
Qualification of Scale Inhibitors for Sub Sea Tie Backs with MEG Injection
Authors: Halvorsen Erling Notto , Halvorsen Anne Marie Koren , Reiersølmen Kristin , Andersen Tore Roberg , Biørnstad Cecilie
Published: April 2009

The Ormen Lange field are using continuous injection of MEG to prevent hydrate formation. The MEG is regenerated and reused, and corrosion control of the multiphase pipelines are accommodated by a combination of pH stabilised MEG and corrosion inhibitors. In order to avoid scaling if formation water is produced a scale inhibitor will be added to the lean MEG.

A comprehensive scale inhibitor qualification program was carried out, and the goal was to qualify one or more scale inhibitors for scale prevention downstream the MEG injection point at subsea wellhead for fully and partial pH stabilisation. 5 suppliers were invited to supply inhibitors to be included in the qualification programme and the suppliers submitted a total of 10 inhibitors. The qualification program included environmental properties, solubility in lean MEG, scale inhibitor screening tests, scale inhibitor dynamic tests, compatibility of chemicals, emulsion and foaming, partitioning, effect on particles formation and settling onshore, consumption/loss of scale inhibitor in the MEG process and stability in MEG regeneration reboiler.

The different tests are described and the results are displayed. The results from the qualification program demonstrated that only few inhibitors satisfied all requirements, the chemicals affect the formation and precipitation behaviour of calcium and iron carbonate and that only one combination of scale and corrosion fulfilled all the requirements. If a scale inhibitor has to be used in combination with a corrosion inhibitor compatibility testing is required. Incompatibility between corrosion and scale inhibitor will cause gunking and scaling. A successful combination of corrosion and scale inhibitor will not increase the corrosivity and simultaneously prevent scaling. It has been observed that such combination of chemicals does not prevent formation of particles but prevents the particles to stick to the surface.

The scale qualification program demonstrates the complexity in qualifying chemicals and the need for a good dialogue between the involved disciplines.
Development of a Methodology for the Optimization of Dehydration of Extra-Heavy Oil Emulsions
Authors: Dalmazzone C. , Noïk C. , Glénat P. , Dang F.
Published: April 2009

With the increasing development of heavy and extra-heavy oil fields, separation operations are becoming more and more challenging compared to separation for conventional oil fields. For in situ bitumen Extra Heavy Oils produced thanks to thermal process, dehydration requires solvent addition, injection of large amount of demulsifier additives, relatively high operating temperature, and long retention times inside the separators. So in order to respect specifications on crude oil and water quality at the lower cost, an optimization of the different parameters involved in the whole process of separation becomes necessary.

In the case of extra-heavy oils, the presence of polar heavy components, such as asphaltenes, structured as a rigid film at the water/oil interface, limits the coalescence phenomena and consequently limits the efficiency of separation by gravity or by using conventional electrocoalescence.

The paper presents a methodology that permits the optimization of water and oil separation in the case of an in situ extra-heavy oil (produced by thermal process). The crude oil was first characterized in terms of rheological behavior and interfacial properties. The dilatational viscoelastic properties of the interface were determined from measurements performed with an oscillating oil drop tensiometer. Properties of emulsification were also investigated by using a specific device named "dispersion rig" that allows the reconstitution of crude oil emulsions under controlled hydrodynamic conditions. Then a laboratory procedure based on electrical stability tests was applied in order to optimize the concentration of demulsifier required for effective water separation.

Finally, the optimal electrical parameters were determined in an electrocoalescer device in presence of the selected concentration of additive. The efficiency of coalescence was measured by following the growth of dispersed water droplets inside the emulsion using Differential Scanning Calorimetry (DSC).
New Viscoelastic Fluid for Chemical EOR
Authors: Morvan Mikel , Degré Guillaume , Leng Jacques , Masselon Chloé , Moreau Patrick , Bouillot Jérôme , Zaitoun Alain
Published: April 2009

This work aims at evaluating a new surfactant based viscoelastic fluid for Chemical EOR applications. The surfactant based fluid exhibits a viscous phase at low concentration and high temperature, useful for improving oil recovery.

The viscoelastic fluid is induced by wormlike micelles formed by self-assembled surfactants. The phase diagram of the surfactant in pure water was established using a pervaporation-based microfluidic device (Leng et al., PRL, 96, 2006). Isotropic wormlike micelles have been observed up to 12 % w/w. In a second step, Particle Tracking Microrheology (PTM) was used to investigate the rheological properties of the fluid for surfactant concentrations below 2% w/w in water. Viscosity at low surfactant concentrations (0.1% to 0.3 % w/w), T= 80°C, in synthetic sea water (3.9 % w/w TDS) and in sodium chloride (2 % w/w TDS) has been recorded. Data shows that the viscosity is weakly dependent on brine concentration and evolves between 3 and 15 mPa.s (γ=10 s-1), for surfactant concentrations between respectively 0.1% to 0.3 % w/w.

The second series of tests consisted of core-flood experiments at 80°C in Clashach sandstone with brine solution (NaCl 2% w/w) containing surfactant concentrations between 0.1 %w/w and 0.3 %w/w. The surfactant is shown to adsorb moderately on the sandstone (50 μg/g) and displace a great fraction of residual oil (from Sor=0.49 to Sor=0.20).

These preliminary results show a strong potential for this new surfactant based viscoelastic fluid in chemical EOR. Compared to other viscoelastic fluids this product shows the following advantages:

Superior viscosity, at low surfactant concentration, in hard brine and at high temperature Better displacement of residual oil in core-flood with moderate adsorption
Successful Scale Mitigation Strategies in Saudi Arabian Oil Fields
Authors: Raju Kris U.
Published: April 2009

Scale deposition, either in the formation or in the production facilities, is a challenging problem in the petroleum industry. Scale mitigation and prevention programs are critical for sustained oil production. It is therefore essential to put in place proper scale management strategies before developing a new field. In addition, exploring new chemical formulations and treatment strategies for current field programs should be examined on a continuous basis to ensure efficient results are achieved.

Saudi Arabian reservoirs have their own set of scale related challenges. Calcium carbonate scales were a major challenge in a majority of wet producers in several carbonate reservoirs across Saudi Arabia. The possibility of a sulfate scaling problem in these fields was minimized by selecting compatible floodwaters and/or creating a sufficient buffer-band to separate the incompatible waters. Phosphonate based scale inhibitor treatments, either encapsulated chemical applied in the rathole or squeezed into the formation, have been highly successful. This has been attributed to the relatively low scaling potentials and associated low threshold inhibitor concentrations, an effective sampling and monitoring strategy and a proactive approach to managing the scaling problem.

Over recent years, well architecture has become more complex, requiring innovative scale mitigation strategies. Vertical wells have been replaced with horizontal wells, horizontal wells with multilaterals, and multilaterals with maximum reservoir contact wells. The future wells include extreme reservoir contact and it is imperative to develop viable and cost-effective treatments for this variety of well types. This paper details how Saudi Aramco mitigated difficult to handle sulfate scaling problems with proper selection of floodwaters in various fields, describes the theoretical background in selecting simple and inexpensive bullhead scale inhibitor squeeze treatments for horizontal wells. We also present technical and economic reasoning for the successful scale management strategy in Saudi Aramco fields with case histories.
Integration of Kinetics into Scale Prediction Software, ScaleSoftPitzer
Authors: Tomson Mason , Fan Chunfang , Lu Haiping , Zhang Ping , Alsaiari Hamad , Kan Amy T.
Published: April 2009

As water cuts increase world wide it becomes more important to control the adverse effects of injected and produced waters. The challenges are greater due to the wider ranges of T, P, and compositions of injection and production fluids. Both equilibrium and rate processes are important to scale and corrosion control. The Brine Chemistry Consortium (BCC) at Rice University has expanded the range of its software to include prediction of brine pH, scale supersaturation for common oilfield scales, mass transport, and the effect of various concentrations of scale inhibitors in the presence and absence of hydrate inhibitors, over a temperature range of about 32 to 400 °F (0 to ≍200 °C), or greater, and pressures from atmospheric to between one and two thousand atmospheres. Many of these models are based upon data developed at the BCC. Comparatively, only limited work has been done to model the kinetics under conditions important to production.

Models have been developed and tested experimentally to include the effects of both methanol (MeOH) and mono-ethylene glycol (MEG) on pH, scale formation, and inhibitor kinetics from zero to 100% MeOH or MEG over the range of conditions commonly found. It has been found experimentally and justified theoretically that once the effect of MeOH or MEG on supersaturation has been modeled, the impact on minimum inhibitor concentration (MIC) and nucleation kinetics for common scales is readily predicted. Even less work has been done to characterize the effects of cosolvents on kinetics.

In order to model small changes in composition, as can be important with iron/zinc, etc., carbonates and sulfide formations, a new high efficiency algorithm that incorporates several numerical methods simultaneously has been developed to assure calculation fidelity even in extreme ranges of composition. Limiting equations will be developed that incorporate some kinetics into brine chemistry modeling for flow in porous media and for flow in pipes.
Modelling Staged Diversion Treatments and Chemical Placement in the Presence of Near Wellbore Fractures
Authors: Stalker Robert , Graham Gordon M. , Oluyemi Gbenga
Published: April 2009

The placement and return of chemical treatments in the near wellbore region is often complicated by a number of factors. For long heterogeneous wells, it is often the case that simple bullhead injection of chemicals can fail to effectively treat the whole length of the well, resulting in key producing intervals being left underprotected and at risk of premature scale-up, impacting oil production. In such cases, the adoption of a more complex staged diversion treatment program can pay dividends, resulting in more effective placement of scale inhibitor and, consequently, longer field return lifetimes. The placement of chemicals in the near-wellbore region can also be perturbed by the presence of fractures. Appropriate modelling of the effect of near-wellbore fractures on chemical placement and return can be difficult, with extensive variations in fracture dimensions and orientations making it difficult to directly measure fracture-network geometry in sufficient detail to model its effect on chemical placement in the near wellbore regions of fractured reservoirs.

In this paper we examine the impact of both artificial and natural micro-fractures on the predicted penetration distance and placement behaviour of injected treatment chemicals, and the consequences of this for inhibitor returns in fractured reservoirs. The paper also presents the results of a series of laboratory tests which provide validation of the fracture model. We also describe the use of a near-wellbore placement simulator to model the placement and chemical return of staged diversion treatments and the impact of these techniques on overall well returns. The algorithms associated with both cases have been incorporated into a new near wellbore simulator and the results compared in a number of case studies. The paper describes the modelling approach and demonstrates its use in modelling near-wellbore chemical placement and propagation.
An Environmentally Friendly Stimulation Fluid for High Temperature Applications
Authors: LePage J. N. , De Wolf C. A. , Bemelaar J. H. , Nasr-El-Din H. A.
Published: April 2009

Matrix acidizing is used in carbonate formations to create flow channels from the formation to the well bore, whereas in sandstone formations the goal is to dissolve materials that impair the well production. However, the use of acids in deep wells has some major drawbacks including high reaction rate and corrosion to well tubulars.

We have discovered a new stimulation chemical that can be used as a replacement for or in combination with acid treatments in deep wells. A polyacid whose structure allows for acidification is described. The polyacidic chelate L-glutamic acid, N,N-diacetic acid or GLDA is manufactured from L-glutamic acid (MSG). The chelate-based fluid very effectively dissolves CaCO3 and it is less corrosive to the equipment and easy to handle.

This paper discusses the reaction of the new GLDA chelate with calcite and will compare its performance with other available chelates, including EDTA, HEDTA, NTA and EDG. GLDA dissolves calcite over a wide pH interval, although it is less effective than HEDTA at > pH 5. A unique property of GLDA is its high solubility - solutions exceeding 40 wt% can be achieved at a ~ pH 2 where HEDTA solubility is limited to ~ 10 wt%. A mole of GLDA acid with a natural ~ pH 1.6 is capable of dissolving up to two moles of CaCO3. Throughout the pH range GLDA appears to be as thermally stable as HEDTA.

As an additive to HCl, GLDA is as effective as HEDTA in preventing precipitation of moderate levels of Fe in spent acids. At high Fe concentration GLDA is slightly less effective than HEDTA on a molar basis – but to deal with high Fe GLDA may be better as significantly higher concentrations of it are possible in various acids. In 28 wt% HCl, HEDTA has limited solubility while GLDA's solubility exceeds 40 wt%.

From an environmental standpoint GLDA, is readily biodegradable and is made from a renewable raw material – monosodium glutamate. GLDA has low toxicity and aquatic toxicity characteristics. As a replacement for HCl acid, GLDA is significantly safer and is less corrosive.
Rheological Properties of a New Class of Viscoelastic Surfactant
Authors: Li L. , Cawiezel K. E.
Published: April 2009

Surfactant-based acid systems were developed over the last few years for diversion to overcome the severe problems caused by polymer residue and crosslinker precipitate after polymer-based system treatments during matrix and fracture acidizing. Two main types of viscoelastic surfactants have been used: amphoteric and cationic. Surfactant molecules can form rod-like micelles and significantly increase the viscosity in the presence of the salts. After acid treatments, the surfactant gel can be broken by mixing with hydrocarbons, external breakers, and internal breakers or by reducing the concentration of salts via dilution with water.

This paper introduces a new type of viscoelastic amphoteric surfactant (amine oxide). It carries a positive charge in the presence of live HCl acid. The effects of acid additives and Fe (III) contamination were examined on its rheological properties. Measurements were made at temperatures from 75-220 °F, and 300 psi at various shear rates from 0.01-935 s−1. Acid additives included corrosion inhibitors, mutual solvent, non-emulsifying surfactant, iron control agents and hydrogen sulfide scavenger.

The apparent viscosity of surfactant solutions prepared in deionized water, live acid, and spent acid was found to be a function of temperature. Calcium chloride increased the apparent viscosity of live acids. Concentration of HCl in the live acid system affected its apparent viscosity. Live acid that contained 12 wt% HCl showed the highest apparent viscosity. Low concentrations of Fe (III) caused an increase in the apparent viscosity. Two immiscible liquids, and then a precipitate were noted as the concentration of ferric ion was increased in live acids. A demulsifer and mutual solvent decreased the apparent viscosity at all temperatures examined. Iron control agents reduced the apparent viscosity of surfactant based acids. The impact of lactic acid on the apparent viscosity was significant, especially at high lactic acid concentrations. Citric acid also reduced the viscosity of surfactant based acids, but cannot be used at concentrations greater than 0.5 wt% because of precipitation of calcium citrate. EDTA slightly reduced the viscosity of surfactant based acids, but the solubility of EDTA in 20 wt% HCl is very low. Up to 1 wt% methanol can be used with this spent acid system at temperatures below 175°F. Higher concentrations of methanol caused significant reduction in the apparent viscosity.
Fast-Inverting, Brine and Additive-tolerant Friction Reducer for Well Stimulation
Authors: Zelenev Andrei S. , Gilzow Gydeon A. , Kaufman Phillip B.
Published: April 2009

Anionic polyacrylamide copolymer friction (or drag) reducers are commonly used in various well stimulation jobs. The effectiveness of friction reduction polymers strongly depends on the compatibility between friction reducing polymers and stimulation liquid to which they are added. Performance of friction reducers can be strongly influenced by the presence of salts, very high or very low pH, or other typical process additives, such as biocides, corrosion and scale inhibitors, hydrogen sulfide (H2S) scavangers, etc. Since most friction reducers are emulsion polymers, an important issue related to their performance is their ability to invert effectively and efficiently upon the addition to the stimulation fluid. A fast enough rate of inversion is especially important, since it determines both the effective onset of optimal friction reduction and its magnitude. Higher friction reduction achieved at the very beginning of a well stimulation will decrease the pumping pressure on a job. We hereby describe novel, fast-inverting friction reducers suitable for effective use in brines and compatible with various additives, such as biocides, clay control agents, and scale inhibitors.
Theoretical Study on the Properties of Cationic, Amidoamine Oxide and Betaine Viscoelastic Diverting Surfactants in Gas and Water Solution
Authors: Sultan A. S. , Balbuena P. B. , Hill A. D. , Nasr-El-Din H. A.
Published: April 2009

pH-sensitive surfactants are becoming increasingly important in many novel applications in various fields including medicine, fabrication, sensing, optics, and oilfield. For upstream industry, it can be used in drilling operation, hydraulic fracturing, acidizing treatments, and sand control. The widespread applications of viscoelastic surfactants (VES) originate from the intrinsic duality in their molecular characteristics. Through many years of experience, various classes of VES have been introduced including cationic, zwitterionic (betaine) and especially, alkylamine oxide surfactants which represent a promising and well-characterized class of responsive fluid. These materials have considerable influence on acid placement in oil well stimulation. As the acid reacts with carbonate minerals in particular, the pH rises and the concentration of calcium chloride, magnesium chloride, or both will increase. The presence of salts and the increase in pH will cause the surfactant molecules to form long rod-like micelles. The behavior of wormlike micelles have drawn considerable interest over the past two decades, both from a theoretical viewpoint as well as for industrial and technological applications, the range of which keeps expanding.

The objective of this paper is to focus on the interaction of different types of surfactant with water using density functional theory (DFT) and classical molecular dynamics (MD) simulations. The structural and energetic properties of five-cationic, four-amidoamine oxide, and six-betaine head groups, (all of which are well known importance for the design of efficient VES acid diverters), are calculated with Hartree-Fock and DFT methods in gas phase and water solution. The conformational behavior of the molecules is studied using the analysis of thermodynamic properties. The information obtained may serve to understand the electronic origin of the factors that determine the properties of these simple molecules and to get insight into the more complex ones in which the tail is not a single methyl group rather a chain of C18-C22, and how they are affected by the water environment.
Mitigation of Reservoir Souring by Nitrate in a Produced Water Re-Injection System in Alberta
Authors: Arensdorf J. J. , Miner K. , Ertmoed R. , Clay B. , Stadnicki P. , Voordouw G.
Published: April 2009

We report the reduction in levels of H2S in produced gas and water using nitrate treatment in an oilfield in Southern Alberta that is under produced water re-injection. Approximately 4,500 m3/day of water is injected, primarily produced water supplemented with make-up water from the outfall of a municipal waste treatment plant. The reservoir is 30-40°C. Calcium nitrate was continuously applied at 150 ppm (as nitrate) into the injection water at a central water plant and distributed to injection wells field wide. A biocide, acrolein, was also applied in weekly batches to treat the injection lines and prevent nitrate-fed biofilm accumulation. After one month of treatment, H2S in the produced gas from one gathering system dropped from an average of 170 ppmv to 110 ppmv (average 3.4 kg/day to 1.8 kg/day). This represents an approximately 50% reduction in produced H2S in the gas. A corresponding decrease in H2S in the produced water was observed. One problematic well maintained an H2S level of approximately 800 ppmv. To treat this well, a nearby injector was started on a weekly treatment of a single batch of calcium nitrate dosed to approximate 600 ppm, based on a seven-day production rate. Sulfide levels in the problem well dropped significantly and over the subsequent 18 months there has been on average <15 ppmv H2S in the produced gas.
Design and Development of a Novel Process To Treat Drilling Fluid Slops: A Positive Environmental and Economic Impact
Authors: Dixit Rahul , Patel Arvind
Published: April 2009

Slop mud, created by water contamination of invert drilling fluids during displacement and cleaning activities, has been successfully treated at source to recover the drilling fluid phase and water phase. This method included treating the slop mud with a biodegradable demulsifier. The recovered drilling fluid can be reconditioned to acceptable properties for re-use or sent for disposal. The recovered/separated slop water phase is contaminated with hydrocarbons and cannot be discharged in an offshore environment unless it meets the discharge criteria of <30 mg/L of oil-in-water. Thus, it becomes imperative for the operator to treat the water at source and reduce the enormous expenses associated with transportation /disposal and embark upon a potentially significant environmental issue. This was achieved by development of an onsite treatment process including filtration, ozonation and phase separation.

A synthetic-based drilling fluid contaminated with water was separated with a biodegradable demulsifier. The addition of the surfactant resulted in phase separation, i.e., separated drilling fluid and water phases. As tested by the approved ISO method, the separated water phase was found to have oil-in-water content of 4,000 mg/L which is unacceptable for discharge. The separated water was then treated with ozone. The ozone-treated water was allowed to separate in two phases, i.e., clarified water phase and organic rich phase. The oil-in-water content of the clarified ozone-treated water phase was found to be 30 mg/L, thus reducing the oil-in-water content by 99%.

This paper will present the demulsification methodology, chemistry of ozonolysis and results obtained to meet or exceed the oil-in-water discharge limits of 30 mg/L. The environmental and economic impact of the process will be discussed.
Lab and Field Study of New Microemulsion-Based Crude Oil Demulsifier for Well Completions
Authors: Yang Y. , Dismuke K. I. , Penny G. S. , Paktinat J.
Published: April 2009

In the petroleum industry, water and oil emulsion formation presents an on-going production issue receiving considerable technical attention. Crude oil/water demulsification effectiveness has been tested using a new microemulsion-based demulsifier (ME-DeM) with an environmentally improved formulation. This ME-based product, tested on a range of crude oils, has been shown to be more effective than comparable commercially available non-ME based demulsifiers (DeM). Results using ME based products for demulsification have demonstrated significant improvements in field tests. Additional field studies are in preparation.
Low Molecular Weight Co-Polymer for Calcium Scale Inhibition at High Temperature
Authors: Senthilmurugan B. , Ghosh B.
Published: April 2009

Calcium scaling problem in production tubular is the most widespread among flow assurance problems. Well intervention in every 3-4 months are common to combat calcite deposition and rapid production decline. In order to minimize the formation of scale deposits, threshold scale inhibitor treatment with polycarboxylates or Phosphorous containing compounds (such as phosphonates or phosphate esters) are common practice in oil industry. In general the polycarboxylates rarely provide optimum performance against calcium carbonate. Higher molecular weight acrylate base products often precipitate as calcium salt. Phosphorous containing scale inhibitors has good overall treatment efficiency, however increasing pressure by environmental regulatory authorities has promulgated search of newer and greener threshold scale inhibitors.

This paper describes synthesis, characterization and efficiency of a high temperature stable, threshold scale inhibitor which is found to work well in low doses at a wide range of pH and temperature. A low molecular weight, maleic acid base co-polymer is synthesized, characterized and inhibition efficiency was compared for calcium carbonate scaling. Molecular weight of the polymer was determined through GPC. FT-IR spectroscopy was used for functional group distribution pattern. Scale inhibition efficiency was measured through chemical screening test, dynamic tube block method and also through electrochemical technique such as constant potential electrolysis and electrochemical impedance techniques. XRD and SEM analysis demonstrated inhibited and un-inhibited crystal structure.

The copolymers showed +90% efficiency in 15-20 ppm dosing at common wellbore temperature (upto 100 °Ċ). For even higher temperature (+120 °C) dose requirement is more. Excellent inhibition property is demonstrated against calcium carbonate scale deposition. Electrochemical studies supported the static and dynamic test results. SEM images demonstrated the scale inhibition of the polymers through adsorption on the growing crystal phases of the nuclei, which resulted in distortion and retardation of crystal growth.
A Coupled Electrical Resistivity–Infiltration Model for Wetting Front Evaluation
Authors: Rucker Dale
Published: April 2009

A coupled resistivity–infiltration model was developed. The infiltration model relies on the analytical solution of a fully developed and sharp wetting front using the Green–Ampt approximation, thereby reducing the resistivity model to the simple two‐layer case. The Green–Ampt approximation is a highly simplistic soil model that has limited applicability to real soils. The forward model demonstrates the effects of a voltage drop with time for a pole–pole, Wenner, and dipole–dipole electrode arrangement for a moving wetting front. The velocity of the wetting front can be obtained directly from the time series curve by normalizing the measured apparent resistivity to the resistivity of the wet layer (estimated from the voltage at time t = ∞) and plotting against the reciprocal of time multiplied by the electrode separation. Furthermore, if the cumulative infiltration or other parameters are known, then the hydraulic conductivity can be calculated.
Spatial Variability of Hydraulic Properties and Sediment Characteristics in a Deep Alluvial Unsaturated Zone
Authors: Botros Farag E. , Harter Thomas , Onsoy Yuksel S. , Tuli Atac , Hopmans Jan W.
Published: April 2009

Statistical analysis and interpretation of heterogeneous sediment hydraulic properties is important to produce reliable forecasts of water and solute transport dynamics in the unsaturated zone. Most field characterizations to date have focused on the shallow 2‐m root zone. We characterized the geologic and hydraulic properties of a 16‐m‐deep, alluvial vadose zone consisting of unconsolidated sediments typical of the alluvial fans of the eastern San Joaquin Valley, California. The thickness of individual beds varies from <5 cm for some clayey and silty floodplain material to >2.5 m for large sandy deposits associated with buried stream channels. Eight major geologic units (lithofacies) have been identified at the site. Unsaturated hydraulic properties were obtained from multistep outflow experiments on nearly 100 sediment cores. Multivariate analysis of variance and post hoc testing show that lithofacies and other visual‐ and texture‐based sediment classifications explain a significant amount of the spatial variability of hydraulic properties within the unsaturated zone. Geostatistical analysis of hydraulic parameters show spatial continuity of within‐lithofacies variability in the horizontal direction in the range of 5 to 8 m, which is approximately an order of magnitude larger than spatial continuity in the vertical direction. Low nugget/sill ratios suggest that 1‐ to 10‐m sampling intervals are adequate for detection of horizontal spatial structure. The existence of thin clay or silt layers within lithofacies units results in only moderate spatial continuity in the vertical direction, however, suggesting inadequate sampling frequency for hydraulic parameter variogram development in that direction.
The Effect of Various Soil Hydraulic Property Estimates on Soil Moisture Simulations
Authors: Gribb Molly M. , Forkutsa Irina , Hansen Aleshia , Chandler David G. , McNamara James P.
Published: April 2009

Models of water movement in unsaturated soils require accurate representations of the soil moisture retention and hydraulic conductivity curves; however, commonly used laboratory methods and pedotransfer functions (PTFs) are rarely verified against field conditions. In this study, we investigated the effects of using soil hydraulic property information obtained from different measurement and estimation techniques on one‐dimensional model predictions of soil moisture content. Pairs of time domain reflectometry waveguides and tensiometers were installed at two depths in the side of a soil pit face to obtain in situ measurements. Undisturbed soil samples were taken near the instruments and subjected to particle size analysis, multistep outflow (MSO), and falling‐head permeability tests to obtain estimates of the soil moisture retention curves. Three scaling methods were then applied to improve the fit of the various estimates to the field data. We found that soil hydraulic property estimates obtained from inverse methods lead to the best simulations of soil moisture dynamics, and that laboratory MSO tests or commonly used PTFs perform poorly. These laboratory and PTF estimates can be dramatically improved, however, by simply constraining the range of possible moisture contents to the minimum and maximum measured in the field. It appears that this method of scaling PTF results can be used to obtain soil hydraulic property inputs of sufficient accuracy for plot‐scale modeling efforts without requiring expensive laboratory or in situ tests.