bluuebunny/crossref_metadata_2025 huggingface dataset:
Reaction of CO2 With Portland Cement at Downhole Conditions and the Role of Pozzolanic Supplements
Authors: Santra Ashok , Reddy B. R. , Liang Feng , Fitzgerald Rocky
Published: April 2009

Interaction between Portland cement and carbon dioxide has attracted much renewed interest because of its implication in geological sequestration of CO2. The fundamental interaction and mechanism have been extensively studied in the literature under ambient conditions. These studies demonstrate that the rate of carbonation is a function of many factors. Examples include: cement type, moisture content, CO2 partial pressure, porosity/permeability, and temperature. Many remedies have also been proposed to counteract such carbonation. However, extrapolating such data to understanding the behavior of carbonation under high pressure and temperature (HPHT) conditions is not trivial. Very recently, attempts have been made by other researchers in the field to understand kinetics of HPHT carbonation. This paper discusses the results obtained on cement specimens treated under water at 200°F and 2,000 psi CO2 pressure for several weeks. As part of this study, we have also very carefully investigated the role of pozzolanic substitution (silica fume and fly ash at various degrees of substitution) in Portland cement blends. Analytical techniques used for characterization included: thermal gravimetric analysis (TGA), Brinell hardness, and X-ray diffraction. The results show that the depth of carbonation during a period of up to 15 days at a given temperature and pressure is directly proportional to the amount of pozzolanic supplement. The results will provide insight into designing cement slurries resistant to carbonation.
Selection and Application of Scale Inhibitor for Application in Oxygenated Produced Water, Norwegian Sector, North Sea
Authors: Marlow D. , Madden A. , Sutherland L. , Jordan M. M. , Sorhaug E.
Published: April 2009

Scale control within produced fluids both topside and downhole in oil/gas production facilities is critical to the effective production of hydrocarbons in a safe, economic and environmentally acceptable manner.

This paper will focus on the scale challenges associated with production of produced water that contains significant amounts of barium, sulphate and dissolved iron ions. While this challenge is not unusual in production operations the presence of dissolved oxygen in the topside process just prior to discharge has resulted in a very challenging environment for barium sulphate scale inhibition.

This paper will outline the challenge of scale control in the presence of ferrous and ferric ion. The inhibitor selection program undertaken will be outlined as well as the critical factors that had to be taken into account given this application was for offshore Norway where environmental characteristics of production chemicals can restrict the choices of chemical suitable for this application.

The development of an application strategy for the selected environmentally acceptable chemical will be outlined along with the monitoring program to ensure not only that the chemical is applied at the correct treatment rate but that it performs as expected from the laboratory performance testing results and can be optimised as brine composition changes with time.
Core Flood Investigation Into Asphaltene Deposition Tendencies in the Marrat Reservoir, South East Kuwait
Authors: Rahmani N. H. G. , Gao J. , Ibrahim M. N. , Bou-mikael S. , Al-Matar B. S. , Al-Ruhaimani F.
Published: April 2009

Asphaltene precipitation can have profound effects on oil production during miscible flooding, heavy oil recovery, or even primary depletion. Even though asphaltene precipitation and eventual deposition have been known to have strong effects on permeability reduction (Turta et al., 1997; Minssieux et al., 1998), quantitative analysis of the process has not been studied extensively. This paper describes experimental work conducted to study the precipitation and deposition tendencies of asphaltenes within the rock material in the Marrat reservoir, South East Kuwait. Live asphaltenic reservoir fluids and carbonate cores of the Marrat reservoir were recovered and used at reservoir pressure and temperature conditions during core flood experiments. The live Marrat reservoir fluid was fully characterized, and subjected to pressure depletion tests to determine the asphaltene onset point at various temperatures.

The results reveal preferential deposition of the precipitated asphaltenes with respect to the rock material. The characterization of the rock materials by CT-Scans had indicated the presence of local occluded porosities. These occluded sites were found to be the main influence on the pattern of deposition seen in the core samples. The study shows clearly that although asphaltenes may precipitate and deposit from the Marrat reservoir fluid, the propensity for permeability damage is in fact determined by the nature of the rock material. In addition, the tendency of the precipitated asphaltenes to aggregate into larger flocs that are generally friable influences the rock damage potential.

Handling and treatment of asphaltenic fluids will continue to impact on reservoir operations, project costs and recovery efficiencies. Understanding the nature of asphaltenes and how they impact on the sub-surface behaviour of reservoir fluids will become more pertinent, as global oil demand forces a move towards heavy oils and / or highly asphlatenic fluids.
Forecasting the Effects of Reservoir Souring From Waterflooding a Formation Containing Siderite
Authors: Burger E. D. , Jenneman G. E.
Published: April 2009

A computer model has been developed to investigate the potential effects of water injection in an offshore oilfield on H2S biogeneration and its subsequent production from the reservoir. The model is based on mechanistic algorithms employed in previous reservoir souring models developed for the Prudhoe Bay and Kuparuk River Fields (Alaska) and the Ekofisk Field (Norway). These mechanisms include the biogeneration of H2S, the partitioning of H2S between oil and water in the waterflooded portions of the reservoir, the reaction of dissolved H2S with siderite to form immobile iron sulfides, and the transport of H2S, oil, water, and gas to producing wells.

The reservoir is currently being seawater flooded although produced water reinjection (PWRI) will soon be initiated. In mid-2006, after less than three years of waterflood at relatively low injection rates, H2S was detected in the gas of several producing wells located close to injectors. It is known that PWRI will result in increased H2S production.

The model was initially calibrated via history match to determine algorithm coefficients associated with siderite scavenging and microbial nutrient availability within the reservoir during seawater flooding. This calibration required historical produced water sulfate concentrations and H2S mass production rates in order to ascertain actual biogenic sulfate reduction levels and the remaining amount of H2S scavenged by the siderite following its partitioning to reservoir fluids. Results indicate that while scavenging by the siderite is likely occurring at a relatively high level, the H2S production rate will increase significantly once water injection rates are increased and PWRI begins.

This paper presents insight as to the importance of water geochemistry in the reservoir souring process and the potential for siderite reactivity, distribution and availability to affect H2S production.
47Ca-Aided Studies of CaCO3 Scaling Rates at Low Saturation Ratios
Authors: Hassfjell S. , Haugan A. , Bjørnstad T.
Published: April 2009

An improved method for continuous on-line measurement of calcite scaling rate in a porous medium at very low saturation ratios based on the radiotracer 47Ca2+ is described. The technique utilizes ?-detectors which measures the precipitation by detection of the g-rays from 47Ca. 47Ca is produced in IFE's nuclear reactor by neutron irradiation of CaCO3, isotopically enriched in 46Ca to 4.1 %. Pressure difference (Dp) and pH is also measured. Several experiments with varying brine-composition, temperature and saturation ratio (SR) have been carried out. Large data sets of relative scaling rates as a function of position and time have been generated. A method for converting these relative scaling rates into absolute scaling rates has been devised. Masses of scale as a function of position at the end of the experiments have been calculated.
Development of Environmental Friendly Iron Sulfide Inhibitors for Field Application
Authors: Chen Tao , Montgomerie Harry , Chen Ping , Hagen Thomas , Kegg Stuart
Published: April 2009

The inhibition of iron sulfide mineral scale formation in oil and gas production is notoriously difficult. High concentrations of scale inhibitors are always needed to provide limited inhibition performance. In addition, it is extremely difficult to test the iron sulfide formation and inhibition in the laboratory.

In this paper, a novel iron sulfide test method has been developed to test the performance of iron sulfide inhibition. Compared with the traditional static jar test and dynamic loop test, this novel developed test method shows good reproducibility and provides a quick and effective way to evaluate the performance of iron sulfide scale inhibition.

An environmentally friendly iron sulfide scale inhibitor has been developed based on this novel developed test method. It provided good performance on iron sulfide inhibition in synthetic field water. The mechanism of iron sulfide inhibition will be addressed.

This paper will give a comprehensive study of iron sulfide formation and inhibition, including iron sulfide prediction,development of test method and development of inhibitors for field application.
Understanding the Mechanisms of Halite Inhibition and Evaluation of Halite Scale Inhibitor by Static and Dynamic Tests
Authors: Chen Tao , Montgomerie Harry , Chen Ping , Jackson Tim , Vikane Olav
Published: April 2009

The inhibition of halite mineral scale formation in oil and gas production is notoriously difficult. High concentrations of halite inhibitors always provide limited inhibition performance. In addition, it is extremely difficult to test halite formation and inhibition in the lab.

In this paper, the dynamic halite loop has been developed to test halite formation and inhibition. Halite formation and inhibition were tested under both traditional static conditions and newly developed dynamic conditions. The results showed inconsistencies based on static jar tests and dynamic loop tests. The possible mechanisms of halite inhibition are discussed.

The following conclusions have been drawn: Compared with the traditional static jar test, dynamic halite loop tests are more representative of halite formation in the field conditions and showed good reproducibility.The newly developed scale inhibitor demonstrated dynamic inhibition performance towards halite formation. Efficiency loop tests showed that the minimum inhibitor concentration (MIC) is less than 200ppm to inhibit halite formation effectively under the test conditions.
Physico-Chemical Interactions Perturbing the Effectiveness of an ATBS-Based Fluid Loss Polymer Used in Oil Well Cementing
Authors: Plank Johann , Lummer Nils Recalde , Dugonjic-Bilic Fatima
Published: April 2009

Water-soluble acrylamide tert-butylsulfonic acid (ATBS)-based copolymers are commonly used to provide fluid loss control for oil well cement slurries. In our study, we investigated the behavior of a CaATBS-NNDMA copolymer synthesized by aqueous radical polymerization with respect to its fluid loss performance in presence of sulfate, chloride and Welan gum and at high temperature (80°C).

First, we found that CaATBS-co-NNDMA adsorbs in high amounts on both cement and silica flour. Its effectiveness relies exclusively on high adsorption onto these mineral surfaces. FLA adsorption may, however, be perturbed by several physico-chemical effects.

Inorganic anions present in high concentrations such as e.g. chloride, as well as organic anionic admixture molecules such as Welan gum, can negatively impact the effectiveness of CaATBS-co-NNDMA. They were found to compete with the polymer for adsorption sites on the surfaces of cement and silica. This way, they reduced the adsorbed amount of the ATBS copolymer. Their impact on the ATBS copolymer generally depends on their anionic charge density, the quality of their anchor group to the cement/silica surface and their concentration.

Elevated temperature (80°C) causes a significant increase in the concentration of solved sulfate present in cement pore solution. As a result of the higher ionic strength, the ATBS copolymer changes its solved conformation from stretched to coiled. Coiling of the macromolecule, however, results in lower adsorption. Through this mechanism, higher temperature reduces effectiveness of the FLA.
Comparative Study of the Working Mechanisms of Different Cement Fluid Loss Polymers
Authors: Plank Johann , Lummer Nils Recalde , Dugonjic-Bilic Fatima , Sadasivan Deependra
Published: April 2009

Oil well cementing uses a variety of chemically different fluid loss polymers, depending on the specific well conditions. In this study, the working mechanisms of polyvinyl alcohol (PVA), polyethylene imine (PEI) and CaATBS-co-NNDMA cement fluid loss additives were investigated. These polymers were selected due to their distinctively different chemical structures.

PVA works by reducing filter-cake permeability through coalescence of hydrated PVA microgel particles which then form a polymer film. At temperatures > 38°C, non-crosslinked PVA starts to dissolve in water. Thus, above this temperature, film formation is no longer possible and fluid loss control is not achieved. Addition of AFS dispersant extends the temperature range at which PVA works from 38°C to about 60°C. The reason behind is that the more anionic and higher soluble AFS prevents PVA from dissolving.

PEI, when used on its own, provides only poor fluid loss control. Its effectiveness is greatly enhanced by the addition of a minor amount of AFS dispersant. Charge titration experiments demonstrate that, when combined in the proper ratio, PEI and the AFS dispersant form a insoluble polyelectrolyte complex which effectively plugs the pores of the filter cake. To achieve optimum performance, PEI and AFS need to be pre-dissolved in the mixing water of the cement slurry to allow the complex to form quantitatively.

In contrast to PVA and PEI, CaATBS-co-NNDMA works by adsorption onto the positively charged surfaces of cement hydrate phases, especially ettringite. Other anionic compounds, e.g. AFS dispersant or even sulfate released from the cement, can interfere with its adsorption and thus reduce its effectiveness through a competitive adsorption mechanism. Therefore, CaATBS-co-NNDMA should not be combined with admixtures which possess high anionic charge density.
Formate Brines for HPHT Well Control—New Insights into the Role and Importance of the Carbonate/Bicarbonate Additive Package
Authors: Howard Siv , Downs John D.
Published: April 2009

This paper describes new research into the role and importance of the carbonate/bicarbonate pH-buffer added to formate based well construction fluids along with a newly developed field method for determining buffer concentrations.

For many years it has been recommended practice to buffer formate brines with carbonate and bicarbonate for corrosion control. Bicarbonate is also the product of the dominant thermal decomposition reaction in formate brine. Since this is an equilibrium reaction, according to Le Chateliers Principle, this additive should cause the equilibrium to establish sooner. Past attempts to demonstrate this have been unsuccessful because it has been difficult to accurately reproduce downhole hydrothermal conditions in laboratory autoclaves. This challenge has now been overcome with specialist equipment that has made it possible to accurately simulate downhole conditions and prove that chemical equilibria do indeed establish downhole. Test results have shown that the equilibrium favors high formate concentrations, meaning that the presence of only relatively small amounts of carbonate/bicarbonate is required for the equilibrium to establish.

Along with the growing understanding of the importance of the carbonate/bicarbonate buffer, there has been a growing demand for a field method to accurately measure carbonate and bicarbonate concentrations as the standard API method for determination of alkalinity does not work in formate brines. The newly developed, simple field method consists of an accurate pH-determination combined with a standard phenolphthalein titration. The method has been extensively tested in the laboratory, and should be reviewed by API for possible inclusion in the API recommended practices.

This new understanding of the roles of the carbonate/bicarbonate buffer has provided us with a better basis for making recommendations as to how to buffer the brine and maintain the appropriate buffer levels for different applications. Combined with the new field method for determining buffer levels, these new insights provide the oil industry with a robust technology to meet the well challenges of the future.
Surfactant-Assisted Synthesis of Metal-Phosphonate Inhibitor Nanoparticles and its Transport in Porous Media
Authors: Zhang Ping , Shen Dong , Fan Chunfang , Kan Amy T. , Tomson Mason B.
Published: April 2009

A surfactant-assisted synthesis route was developed to form nanometer sized metal-phosphonate particles to expand its use in the delivery of phosphonate inhibitors into porous media for scale control. Aqueous solutions of calcium chloride and zinc chloride were mixed with basic solution containing phosphonate scale inhibitors, such as diethylenetriamine-penta (methylene phosphonic acid) (DTPMP) or BHPMP in the presence of sodium dodecyl sulfate (SDS) and/or tetradodecylammonium bromide (TTAB) surfactants. The physical and chemical properties of the fabricated nanoparticles have been carefully evaluated. A large number of fabrication procedures are screened and only those that yield the metal-phosphonate particles in the diameter of 50-200 nm with various shapes are further evaluated. Furthermore, these nanoparticles should meet the criteria of forming stable suspension over 12 hours at 70°C and up to 2% KCl. The nanoparticles are capable of traveling through the porous media and depositing into the formation during a shut-in period. After that, production is resumed and the inhibitor nanoparticles are dissolved into the produced fluid to prevent scale formation. The potential application of synthesized nanoparticles in inhibitor treatment in oil fields was tested by laboratory squeeze simulations, where the nanoparticles can be placed at distance away from the injection port and retained by the porous media and returned slowly as flow back with synthetic brine. The retention and long term flow back performance of metal-phosphonate particles will be reported.
Molar Ratio of Ca2+ to Fe2+ in the Supersaturated Solution of Iron Carbonate and Calcium Carbonate and in the Precipitate: Relation and Interpretation
Authors: Alsaiari H. A. , Kan A. , Tomson M. B.
Published: April 2009

Calcium and iron ions are commonly observed in treated waters. Their carbonate salts are widely found in production lines of separation plants and gas and oil wells. Extensive studies have been made on calcium carbonate salts. On the other hand, little attention has been paid to ferrous iron carbonates and iron sulfide [Tomson et al., 1991; Jonson et al., 1991; Braun, 1991; Greenberg et al., 1992, Yean et al., 2008]. This is probably attributed to the reactivity of ferrous iron and the difficulty in the laboratory to completely prevent the reactions of ferrous iron from oxygen. Several experimental designs and sampling procedures are proposed in the literature. Nonetheless, none of them guarantee complete avoidance of oxygen. In addition, little information is available about ferrous iron carbonate, no reports have been found in the literature focusing on the interaction of iron/calcium carbonate common to nearly all oil field systems. Most of the reports found in the literature focus on the topic in terms of impurities and their influence in crystal structures and/or in their geochemical interaction at low temperatures (20-30°C) [Langerak, et al., 1999; Meyer, H.J., 1984; Herzong et al., 1989].

This work has the following objectives; 1) to study the interaction between ferrous iron and calcium ions simultaneously toward carbonate ions in supersaturated solution in a continuous stirred tank reactor (CSTR), 2) to establish an acceptable experimental design as a preparation step to study the behavior of iron sulfide salts. The experiments were conducted in 0.5 M NaCl solution at 55 °C. The pH values were between 6.2 and 7.8. It was found that calcium ions have a strong influence in increasing the solubility of iron carbonate. On the other hand, ferrous iron did not significantly affect the solubility of calcium carbonate. This might be due to increasing the stability of ferrous iron carbonate complexes in the presence of calcium. Also the molar ratios of calcium to iron in the solution were compared with their molar ratios in the precipitated salts solid. It was found that the relation was greater than unity; Rsolid/Rsolution = 2.39. Although calcium carbonate has higher solubility and also the saturation index of calcium carbonate was lower than that of ferrous iron carbonate during the experiment, however, calcium carbonate has a preference to precipitate. This result seems to be in agreement with water dissolution rates of divalent ions and also with reaction rate constants of iron carbonate and calcium carbonate reported in the literature.
Self-Healing Cements that Heal without Dependence on Fluid Contact
Authors: Reddy B. R. , Liang Feng , Fitzgerald Rocky
Published: April 2009

Oilfield-cement compositions capable of self-healing cracks/fractures in set cement without depending on contact with a fluid, such as water or oil, have been developed. Traditionally, such compositions include additives that are capable of swelling when exposed to fluids like water or oil, for example. Presumably, if the cement develops cracks/fractures or flow channels caused by shrinkage or debonding and allows fluid flow, the swelling additive exposed to such fluids will swell, thereby healing the flow path. The current technology employs additives that swell either in water or oil, but not both. Such additives do not swell when exposed to gas, irrespective of whether the gas is carbon dioxide or a hydrocarbon. Dependence on additives to swell and block flow channels after contact with a specific type of fluid hinders the self-healing effectiveness of the cement composition. As a result, designing cement compositions for field applications requires prior knowledge of the type of fluids that the cement may come into contact with, not only through the productive lifetime, but also after abandonment of the well. Alternately, multiple additives that will swell and seal in both water and oil might need to be included in the initial cement design. Even in the latter case, the compositions still cannot offer protection against gas flow.

A new class of elastomeric additives that do not depend on the nature of fluid to seal cracks is presented in this paper. Performance of these additives in a variety of self-healing tests based on flow studies through cracked cement cores will be presented. In addition, the importance of specific structural features of the additives that render them suitable for inclusion in self-healing cement compositions will be discussed.
Enhanced Effect of Transition Metal Ions on Inhibitor Squeeze Treatments
Authors: Fu Gongmin , Kan Amy T. , Tomson Mason B.
Published: April 2009

Scale inhibitor squeeze treatment is often used to prevent scaling in the oil field. However, some inhibitors show poor retention in the conventional squeeze treatment, where less than 50% of the inhibitors are retained in the formation. It has been shown that the addition of transition metal ions, such as Zn2+, and Cu2+ significantly increases inhibitor retention and effectiveness. In this study, calcite and oil field core material were used in laboratory squeeze simulations to test the squeeze efficiency of phosphonate and polymeric scale inhibitors. Three squeeze procedures, whereby transition metal ions are added into inhibitor pill, overflush solution, and preflush solution were compared. It was demonstrated that over 90% of BHPMP and PPCA were retained when Zn2+ and Cu2+ were added in the pill, overflush and preflush solution. Simulation indicates that squeeze life may be improved by a factor of 60 or greater if these new squeeze procedures are used. The mechanism of enhancing inhibitor retention is also discussed in the paper. It is probably due to the formation of transition metal-inhibitor and Ca-inhibitor co-precipitate, and more stable complex of transition metal ion with inhibitor. Zn2+ displacing Ca2+ from the calcium containing rock and forming a new solid phase ZnCO3 have been evidenced. This solid will enhance the inhibitor depositing in the formation and probably also serve as a sulfide scavenger to remove hydrogen sulfide from conate brine in the formation.
Effects of Monoethylene Glycol on Carbonate Equilibrium and Calcite Solubility in Gas/Monoethylene Glycol/Water/Salt Mixed Systems
Authors: Lu Haiping , Kan Amy T. , Tomson Mason B.
Published: April 2009

Monoethylene Glycol (MEG), HOCH2CH2OH, is an important raw material with numerous industry applications, which include polyester synthesis, automobile antifreeze, coolant, and aircraft anti-icer. In oil and gas industry, MEG is commonly used as a gas hydrate inhibitor, which can prevent the formation of gas hydrate during the production of oil and gas in oil wells. However, MEG has the adverse effects on the solubility of minerals. The lowering solubility of minerals will result in the precipitation of mineral scales, which is another serious problem in the production of oil and gas and also causes scaling problems during glycol regeneration.

Despite the importance of scale problems with MEG in oil production, there are few investigations on the solubility of mineral salt in the co-solvent of MEG and brine solutions due to the complexities of this mixed-solvent system. In this research, experiments have been conducted on the carbonate equilibrium and the solubility of calcite at 2°C- 70°C, 0-6.5 m ionic strengths, and 0-100% MEG. MEG activity coefficients with respect to dissolved CO2, bicarbonate, carbonate, and calcium are determined as a function of temperature, ionic strength, and mole fraction MEG in mixed solvent.

A self-consistent activity model is proposed based on the data obtained from this study. Pitzer theory was used to calculate the effect of salt and a Born type equation was applied to analyze the effects of MEG. This model can predict mineral scales solubility in the presence of MEG and brine solutions, provide a better understand of effects of MEG on solubility of scales, and gain an insight into the scale inhibitor studies.
Testing Gas Well Deliquification Chemicals at Real Downhole Conditions
Authors: Pakulski Marek
Published: April 2009

Continuous or batch treatment of low-pressure gas producing wells with foaming agents is a common and cost-effective method to sustain production from such wells. The foam additives convert gas and brines into foams lowering the bottomhole hydrostatic pressure and increasing liquids unloading from the well; thus, preventing wells from filling with water and "drowning". The process can utilize existing formation gas or lift-gas injected into the well. Water to be unloaded can be from nearly drinking quality to supersaturated brine. Selection of a proper foaming agent for foam assisted well deliquification at downhole conditions becomes more complicated in deeper hot wells and with influx of various amounts of oil and condensate in well liquids. Common and standard bench foam testing methods are insufficient to assess foaming agents efficiency at extreme environments.

Answering the need for more realistic testing methodology of foaming agents an automated heated and pressurized foam testing column was constructed. The device is capable of injecting gas, brines, condensate and foaming agents at high pressure and bottomhole temperatures encountered in even deepest wells. Foaming agents' effectiveness is measured at true well conditions. The paper describes design, testing procedures and compares results against older testing methods.

We describe here first laboratory obtained data on foams vertical movement at high pressure and high temperature wellbore conditions. Measurements of foaming agents well deliquification abilities at temperatures above 100°C (212°F) are impossible to obtain with any other existing instrument. The results validate the original scientific idea behind constructing of a device measuring foaming agent's effectiveness at below critical velocity gas flows based on brine retention in the column. The foam column is becoming an indispensable tool for development of foaming agents to be used in challenging environments. This apparatus allowed moving the ultimate new product testing from the field back to the lab and avoiding costly mistakes.
Troubleshooting Nitrate Field Injections for Control of Reservoir Souring
Authors: Jack T. R. , Grigoryan A. , Lambo A. , Voordouw G. , Granli T.
Published: April 2009

Nitrate addition to injection water has been used to control the development of reservoir souring through microbial production of hydrogen sulfide particularly in seawater floods offshore. Current interest is in the application of this technology to produced water recycle injection (PWRI) systems in onshore fields. Long term field observations and analyses for PWRI operations in both high and low temperature oil reservoirs have provided insight into issues and potential challenges that can arise in the application of nitrate as a control treatment for souring. This paper will describe the rudiments of a trouble shooting scheme that is being developed to assist in the optimization of field programs.
Viscometer for Opaque, Sealed Microemulsion Samples
Authors: Salinas Jose Lopez , Miller Clarence A. , Koh Yoo Kuy Hun , Puerto Maura , Hirasaki George J.
Published: April 2009

Formulation of surfactant EOR systems usually involves multiple salinity scans of the phase behavior of crude oil, surfactant, and brine systems. Usually, the measurements are made in sealed pipettes for accurate volume measurements without fluid loss. The volumes of oil and water solubilized into the microemulsion phase are observed to determine the optimal salinity and estimate the interfacial tension. Viscous emulsions and surfactant-rich condensed phases are not desirable. However, the only estimate of viscosity from the salinity scans is the movement (or lack of movement) of the interfaces upon tilting of the tube.

A falling-sphere viscometer with multiple, ring-shaped, inductive proximity sensors is described. The device uses 0.78 mm, gold-coated, paramagnetic, 440 stainless steel spheres. With this size sphere, it is possible to accurately estimate the viscosity of fluids from 1 to 1,200 cp. The spheres are paramagnetic, so they can be lifted to the top of the tube with a magnet, and meet the constraints of a Reynolds number less than 800 for low viscosity fluids, and a velocity fast enough to be detected for a high viscosity fluid. A data acquisition system control a set of four sensors for signal conditioning and time recording. When the same phase spans the space between a pair of sensors, its viscosity can be estimated directly from the transit time of the sphere. When two or three phases span the space between a pair of sensors, the viscosity of the undetermined phase can be estimated from the transit time across it after correcting for the transit times across the upper and/or lower phases. Thus the viscosity of a middle-phase microemulsion can be estimated even if it spans only a small fraction of the distance between sensors.

The system has been used to measure viscosities of lower-, middle-, and upper-phase microemulsions at ambient temperature. Also, apparent viscosities of macroemulsions and of the "colloidal dispersion" layer at the top of a lower-phase microemulsion have been measured.
Fractional-Flow Theory of Foam Displacements with Oil
Authors: Ashoori E. , van der Heijden T. L. M. , Rossen W. R.
Published: April 2009

Fractional-flow theory provides key insights into complex foam EOR displacements and acts as a benchmark for foam simulators. In some cases with mobile oil present the process can be represented as a two-phase displacement. We examine three such cases.

A first-contact-miscible gas flood with foam injection includes a chemical shock defining the surfactant front and a miscible shock defining the gas front. The optimal water fraction for the foam, that gives the fastest oil recovery, maintains the gas front slightly ahead of the foam (surfactant) front.

The success of a foam process with first-contact-miscible CO2 and surfactant dissolved in the (supercritical) CO2 depends on the strength of foam at very low water fractional flow, as for a surfactant-alternating-gas (SAG) process with surfactant dissolved in water. The speed of propagation of the foam front depends on surfactant adsorption on rock and also on the partitioning of surfactant between water and CO2, but is always less than the velocity of the foam front in a SAG flood with surfactant ahead of the gas. A foam with surfactant that is much more soluble in water than in CO2 would propagate slowly, regardless of surfactant's absolute solubility or the level of adsorption on rock. An aqueous surfactant preflush can speed the advance of foam, however.

An idealized model of a surfactant flood pushed by foam suggests that it is best to inject a relatively high water content in the foam to ensure that the gas front remains behind the surfactant front as the flood proceeds. Any gas that passes ahead of the surfactant front would finger through the oil and be wasted.

We present simulations to verify the solutions obtained with fractional flow methods and illustrate the challenges of accurate simulation of these processes.
Chromatographic Separation of Chemicals in Alkaline Surfactant Polymer Flooding in Reservoir Rocks in the Daqing Oilfield
Authors: Li Daoshan , Shi Mingyi , Wang Demin , Li Zhao
Published: April 2009

Alkaline-surfactant-polymer (ASP) flooding have been studied and applied in Daqing oil field for more than 15 years, where eight ASP pilot tests of different scales had been conducted and five ASP foods have been pilot tested. Incremental recoveries are from 19.4 to 25%(OOIP). Since the adsorption of each chemical component would have significant impact on the cost-effective and recovery efficiency of the ASP flooding process, laboratory experiments were conducted to investigate the adsorption of each component in reservoir rocks as well as the analysis of the mineral contents and the clay compositions in the reservoir rock taking from the ASP test area in the Daqing Oilfield.

In the adsorption study, four chemicals; a surfactant, an alkaline agent, polymers, and a sacrificial agent were used. The results showed that the adsorption of surfactant does not obey the Langmuir adsorption isotherm and has a maximum value of 0.6 mg/m2, but adsorptions of alkali and polymer chemicals do obey the Langmuir adsorption isotherm. Adsorption tests also indicated that the adsorption of surfactant could be reduced by 30% with the addition of 0.15wt% of a bio-surfactant as a sacrificial agent into the key surfactant, ORS-41, solution. In addition to adsorption tests, retention (dynamic adsorption) tests were conducted using reservoir core plugs. The results showed that the sequences and peaks of relative concentration (C/C0) of chemicals in effluent are polymer, alkali, and then surfactant. The results also showed that the adsorption of the surfactant is the greatest among all chemicals. This phenomenon indicates the chromatographic separation of three chemicals transport process in cores. The chemical analysis and the chromatographic separation of these chemicals in produced fluids the previous three pilot tests showed consistent results with laboratory studies, and the degree of retention of the surfactant is proportional to the clay content in field tests.

Based on these findings, an ASP flooding pilot test was conducted in the Daqing Oilfield in 1994 with the combination of a bio-surfactant and the key surfactant, ORS-41. Since the adsorption of the bio-surfactant is stronger than ORS-41, the bio-surfactant was used in the ASP pilot test to lower the amount of the more expensive ORS-41. However, the effect of bio-surfactant as sacrificial agent on chromatographic separation of chemicals in ASP flooding (or surfactant lag) is not obvious.
Spectroscopic Determination of Naphthenic Acid Composition from Various Calcium Naphthenates Field Deposits
Authors: Ahmed Mohammed Murtala , Sorbie K. S.
Published: April 2009

Naphthenate formation in oil production systems has been recognised for some times as a troublesome and potentially expensive flow assurance problem. The production of biodegraded or higher TAN (total acid number) crude oils together with the changes in both chemical and physical properties during production operations may trigger naphthenate formation. These naphthenate deposits may form as either a soft emulsion type sodium naphthenate or as a hard solid deposit of calcium naphthenate.

Within the Flow Assurance and Scale Team (FAST) at Heriot-Watt, we have carried out an extensive series of naphthenic acid extraction and characterization experiments on a range of field sodium and calcium naphthenates samples from around the world. In particular, we have analysed these samples using the negative ion mass spectroscopic techniques, ESMS and APCI-MS. In this paper, we present results of naphthenate extract analyses for calcium naphthenate field deposits from the North Sea and Asia. Some of the samples analysed show the presence of both lower and higher molecular weight naphthenic acids in the spectra, whilst others showed mostly the presence of higher molecular weight naphthenic acids with minor traces of lower molecular weight species. Results from this work have now shed more light on the naphthenic acid composition in different field calcium naphthenates, which has been a topic of debate for some time. Results are also presented from novel re-precipitation experiments using the naphthenic acid extract and synthetic brine. Both APCI-MS and ESEM/EDAX data are presented for these laboratory formed precipitates. These results lead to some clear conclusions on the final composition of calcium naphthenate deposits.
Completion Fluids Challenges in Maximum Reservoir Contact Wells
Authors: Al-Yami A. S. , Nasr-El-Din H. A.
Published: April 2009

Most drill-in fluids contain weighting solids. The overbalance required between the drill-in fluid and reservoir to keep the well under control will force the weighting solids to enter the formation and cause damage, Bailey et al. (1999). Horizontal wells are intended to maximize reservoir drainage and minimize water production due to water conning, Beal et al (1996). However, unlike vertical wells, poor acid distribution occurs during matrix acidizing. Coiled tubing cannot reach the total depth of the well because of some limitations such as large washouts, length of the reel and diameter of the coil, which makes acidizing horizontal wells non-effective, (Nasr-El-Din et al., 2004b). In addition, conventional weighting solids used in drill-in fluids when entered the reservoir formation will not easily flow back into the wellbore when production resumes, Bailey et al. (1999). Format drill-in fluids with low solids content can then be used in horizontal wells, Simpson et al. (2005). However, they are expensive and require close monitoring of the pH, Nasr-El-Din et al. (2004a). Formation damage from all drilling fluids are still a concern and they are more problematic in horizontal and maximum reservoir contact wells and their damage require chemical and mechanical removal methods.

Cleanup of drilling-fluid filter cake in long horizontal and multilateral wells is a difficult task. Both mechanical water jetting and/or circulating new volumes of low solids drilling fluids have certain limitations. Other methods of removing filter cake such as using chemical means for example mineral acids, esters, oxidizers, chelating agents, viscoelastic surfactants and enzymes are also limited at certain conditions.

Intensive lab work has been done to evaluate mechanical and chemical methods in removing formation damage induced from drilling fluids. However, no work was done before to the best of author's knowledge in comparing these removal methods (mechanical and chemical) for different drill-in fluids supported with field cases to provide guidelines on when to use or avoid.

The paper will review chemical means used to remove filter cake. Limitations of each method are highlighted. Implications to the field are discussed.
A New Look at the Viscoelastic Fluid Flow in Porous Media—A Possible Mechanism of Internal Cake Formation and Formation Damage Conrol
Authors: Dehghanpour H. , Kuru E.
Published: April 2009

Fluid loss control is generally achieved by increasing the shear viscosity of the fluid and developing internal/external filter cake using fluid loss control additives. If the viscosifiers and fluid loss control additives are not selected properly, both mechanisms may lead to significant reduction of permeability. Moreover, increasing fluid shear viscosity may not be desirable all the time due to the high annular pressure losses (i.e., ECD limit), in particular, when drilling long horizontal and extended reach wells.

In this paper, a new methodology is presented to formulate an "ideal well fluid", which effectively reduces fluid loss into formation without causing additional frictional pressure losses in the well. Blends of a water-soluble resin (Polyox) with different molecular weight distribution (MWD) and similar average molecular weight (Mw) were prepared. The Polyox blends were then used to prepare aqueous polymer solutions, which had similar shear viscosity but significantly different elastic characteristics (i.e., normal stress difference and relaxation time).

Core flow experiments have been conducted to investigate the effects of viscoelastic fluid rheology on the formation of "internal cake" (i.e., frictional pressure drop). Since both fluids have the same shear viscosity but different elastic properties, it was possible to see the effect of fluid elasticity on the frictional pressure losses alone. The fluid with higher elasticity exhibited significantly higher resistance to flow through porous media than that of the fluid with lower elasticity.

Experimental results indicated that filtration of a polymer based fluid into porous media could be considerably reduced by controlling the MWD of the polymer at constant shear viscosity and concentration of the polymer. Furthermore, formation damage risk of polymer based well fluids could be minimized without inducing additional pressure drop due to fluid flow inside the well.
Improved Oil Recovery with Chemicals in Carbonate Formations
Authors: Tabary René , Fornari Antoine , Bazin Brigitte , Bourbiaux Bernard , Dalmazzone Christine
Published: April 2009

A large quantity of world's oil reserves is contained in carbonate reservoirs. Most of them are naturally fractured and mixed-wet to preferentially oil-wet which are unfavourable conditions for spontaneous water imbibition. This research proposes a combination of experimental methods for the evaluation of the efficiency of chemicals to recover oil from mixed-wet to oil-wet cores. The study is oriented towards the acquisition of data required for modelling chemically-assisted imbibition mechanisms.

Both spontaneous and forced imbibition experiments were performed on outcrop carbonate cores, following specific procedures for establishing given wettability indices. Alkalis were used with and without surfactants as chemical additives of the imbibing aqueous phase. Spontaneous imbibition tests were carried out with reactive and non-reactive oils, in order to dissociate/investigate the effects of alkali and surfactants on the water-oil InterFacial Tension and on the rock wettability. The alkalis exhibited a striking imbibition enhancement with a reactive oil. With a non-reactive oil, imbibition was moderate in the presence of alkali without surfactant. Formulations including a surfactant and an alkaline agent were evaluated and the results are discussed in relation with the InterFacial Tension. Moreover, the wettability index determined through centrifugation and relative permeability data were found to be consistent with the results of spontaneous imbibition tests. Finally, the generic experimental methodology proposed herein delivers a consistent set of relevant parameters for assessing and modelling the recovery efficiency of alkali-surfactant solutions in many fractured carbonate reservoirs with unfavourable recovery prognosis.
Development of Fourier Transform-Ion Cyclotron Resonance Mass Spectrometry Protocol for the Analysis of Asphaltene Field Samples and Solubility Fractions
Authors: Schrader W. , Panda S. K. , Andersson J. T. , Salisbury M. , Grutters M. , Shepherd A. G.
Published: April 2009

One of the most important issues in oilfield chemistry is the troublesome occurrence of organic and inorganic solids which may form downhole in the reservoir, wellbore, topsides and/or in pipelines. Asphaltenes are a class of compounds in crude oils, defined in solubility terms that under certain conditions are known to precipitate and deposit. This may lead to very expensive remediation and treatment operations. Over the years much research has been carried out on asphaltenes. Yet the exact chemical nature of these species still remains unknown. The determination of asphaltene molecular weight distributions in conjunction with the identification of compound classes is a major challenge in the prediction of asphaltene problems with petroleum fluids. Fourier-Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS) is a technique well-suited for this purpose, due to its unmatched resolution and the possibility of providing information otherwise not available from more traditional bulk elemental analysis methods. We have designed a preliminary analytical protocol with this objective in mind. It involves the sample preparation (e.g. sulfur selective chromatography and derivatization) in combination with FT-ICR MS. Initial data show that the predominant compounds in the asphaltene samples investigated were species in the mass range of 200-1100 Daltons containing various functionalities, including nitrogen-, sulfur- and oxygen-heterocycles. It was possible to see clear differences between asphaltene field samples and solubility fractions. Further work should target the correlation of this information with the precipitation of asphaltenes from problematic fluid samples.