bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analytical Methods for Maintaining Quality Assurance of Recycled Fracturing Fluids
Authors: Hanes R. , Parker M. , Slabaugh B. , Weaver J. , Walters H. G. 
Published: December 2007

Abstract
Water-based hydraulic fracturing fluids typically use guar or derivatized guar to produce the properties required for proppant transport and fluid-loss control during fracturing operations. Guar is a high molecular weight polysaccharide that is water-soluble, generates good viscosity at low concentrations, and is economical. Low-viscosity base solutions are crosslinked easily with a variety of metal ions to generate highly elastic fluids that have excellent proppant suspension capability.
After a fracturing treatment is completed, this highly viscoelastic fluid must be degraded to a near water-thin liquid to facilitate fluid recovery. To accomplish this, the polysaccharide is extensively degraded through the use of a variety of chemical additives that were included in the fracturing fluid formulation. The resulting flowback fluid is not useful, and generally requires disposal.
A new hydraulic fracturing fluid, whose rheology is reversible and is controlled by pH, eliminates the need for polymer degradation. Because of this uniform viscosity reversal, the recovered frac fluid volume after well flowback approaches 100%. More importantly, since degrading agents are not required, the recovered fluid can be reused for subsequent fracturing treatments. This process results in reduced environmental demand by decreasing the volume of chemicals required for a fracturing campaign, the volume of water required, and reduced disposal cost.
To reuse recovered fracturing fluid, several nonconventional fluid analyses are required to ensure fluid stability and performance quality. This paper describes the onsite analytical procedures developed to analyze key chemical variables required for fluid reconstitution, making frac fluid reuse a reality.
Evaluation of CO2-Brine-Reservoir Rock Interaction with Laboratory Flow Tests and Reactive Transport Modeling
Authors: Wellman Tristan P. , Grigg Reid B. , McPherson Brian J. , Svec Robert K. , Lichtner Peter C. 
Published: December 2007

Abstract
Sequestration of carbon dioxide (CO2) in geological formations is one proposed method for isolating anthropogenic CO2 from the atmosphere. Determining the viability, risks, and optimal locations of sequestering CO2 in the subsurface requires detailed knowledge of the complex interactions among CO2, rock matrix, and pore fluids under appropriate in situ pressure and temperature conditions. Many physical and chemical processes are known to occur both during and after geologic CO2 injection, including diagenetic chemical reactions and associated permeability changes. Although it is commonly assumed that CO2 sequestered in this way will ultimately become mineralized, the rates of these changes, including CO2 hydration in brines, are known to be relatively slow. Together with hydrated CO2, cations from produced brines may form solid-state carbonate minerals, ostensibly providing permanent sequestration.
We used results of earlier laboratory CO2-brine flow experiments performed in rock core to calibrate a reactive transport simulator. We are using the calibrated model to estimate in situ effects of a range of possible sequestration options in depleted oil/gas reservoirs. The code applied in this study is a combination of the well known TOUGH2 simulator, for coupled groundwater/brine and heat flow, with the chemistry code TRANS for chemically reactive transport.
Variability in response among rock types suggests that CO2 injection will induce ranges of transient and spatially dependent changes in intrinsic rock permeability and porosity. Determining the effect of matrix changes on CO2 mobility is crucial in evaluating the efficacy and potential environmental implications of storing CO2 in the subsurface.
A New Approach to Inhibitor Squeeze Design
Authors: Kan A. T. , Fu G. , Al-Thubaiti M. , Xiao J. , Tomson M. B. 
Published: December 2007

Abstract
Oil field scale treatments can become more difficult when working with deeper non-conventional wells. Inhibitor squeeze is generally the most efficient scale treatment technology. However, inhibitor squeeze treatment is based more on experiences than mechanistic understanding of how the chemical interacts with formation rock and how it flows back. Better mechanistic understanding of the phosphonate/rock interaction is needed to derive innovative squeeze treatment for newer non-conventional wells. Significant progress has been made toward developing a quantitative understanding of the inhibitor/rock interaction, kinetics, stoichiometry, and equilibrium as inhibitors are injected into a formation and allowed to flow back. Four common oil field inhibitors (three phosphonates and one polyacrylate) are compared. In addition to calcite (CaCO3) in the reservoir rock, at least three phosphonate phases appear to be important, a low Ca and a high Ca amorphous Ca-P salts and a crystalline Ca-P salt, where "P" refers to a phosphonate molecule. The inhibitor/rock interaction follows four sequential reactions: (1) Limited acid attack of calcite; (2) Formation of a monomolecular coverage of phosphonate; (3) Reduction of further calcite dissolution due to surface poisoning by the Ca-P coating; (4) Precipitation of Ca-P solid with either low Ca or high Ca stoichiometry. Quantitative relationships between type of inhibitors, inhibitor concentration and acidity, kinetics of calcite dissolution and calcium-phosphonate precipitation are developed for the first time using a rule-based automatic approach. Consequences of the observations on squeeze design and scale inhibition will be discussed.
A Wettability Evaluation Method for both Gas-Liquid-Rock and Liquid-Liquid-Rock Systems
Authors: Li Kewen , Horne Roland N. 
Published: December 2007

Abstract
Methods that can be used to determine the wettability in both gas-liquid-rock and liquid-liquid-rock systems have been few. To this end, a method is proposed to evaluate the wettability in either gas-liquid-rock systems or liquid-liquid-rock systems. The method can be used to evaluate the wettability at a specific wetting phase saturation if the capillary pressure and relative permeability at this fluid saturation are known. The validity of the proposed technique was tested qualitatively and quantitatively using experimental data of capillary pressure and relative permeability from different systems. The wettability index calculated using the proposed technique was greater in the drainage case than that in the imbibition case, which is reasonable and consistent with the present understanding. The calculated wettability indices in gas-oil-rock systems were greater than in oil-water-rock systems as expected. Results also showed that the wettability index calculated using the proposed method may or may not be independent of fluid saturation in the cases studied.
Effective Control of Exotic Mineral Scales Under Harsh System Conditions
Authors: Yuan M. , Williamson D. A. , Smith J. K. , Lopez T. H. 
Published: December 2007

Abstract
In the Mobile Bay area of the Gulf of Mexico, occurrence of unique mineral scales in producing wells and flow lines has been a challenge to maintaining normal oil and gas production; and it has a high impact on operation cost. In addition to common scales (calcium carbonate and barium sulfate), the produced water often has a tendency of forming "exotic" scales, such as calcium fluoride, zinc sulfide and lead sulfide, which can cause plugging of subsea safety valves, and restrictions in the production flow lines, production headers and surface vessels. Furthermore, the problem has been compounded with the harsh system conditions (high temperatures, and high TDS and high calcium brines). This paper describes a successful scale inhibition program that has been developed from a careful analysis of the system and nature of the problem, a comprehensive laboratory product development and evaluation, and the implementation of the chemical treatment in the field.
Synthetic Polymer Fracturing Fluid for High-Temperature Applications
Authors: Funkhouser Gary P. , Norman Lewis R. 
Published: December 2007

Abstract
High-temperature fracturing fluids based on guar degrade rapidly at temperatures above 300°F, complicating stimulation of high-temperature wells. A synthetic polymer was developed that overcomes the hydrolytic stability limitations of polysaccharides while maintaining the ability to crosslink and break the fluid.
This paper presents the initial laboratory development of a fracturing fluid using the synthetic polymer. Hydration is rapid compared to guar, eliminating the need for special hydration tanks or equipment when mixed on-the-fly. Crosslinking is achieved with conventional zirconium crosslinkers to yield a highly viscoelastic gel. Static and dynamic fluid-loss test data are presented and compared to guar-based fluids. Dynamic effects on fluid-loss rates were negligible compared to a borate-crosslinked guar fluid over a wide range of matrix permeabilities. Rheological characterization up to 400°F was performed with a Fann Model 50 viscometer and clearly demonstrated the synthetic frac fluid's high stability relative to guar. Additionally, effects of various breaker types are presented.
New Surfactant for Chemical Flood in High-Salinity Reservoir
Authors: Zaitoun Alain , Fonseca Claudio , Berger Paul , Bazin Brigitte , Monin Nicole 
Published: December 2007

Abstract
Evaluation of the chemical flood potential in the Chihuido de la Sierra Negra field, Argentina, has been carried out using several different recovery scenarios. This field has been submitted to extensive waterflooding for several years, and surface facilities have been designed to recycle produced brine as injection brine. The use of produced brine, as chemical solution make-up water is therefore very advantageous from both an operational and economical point of view. However, the formation brine contains around 110,000 PPM Total Dissolved Solids with around 2,800 PPM divalent cations. This makes the selection of the proper surfactant extremely difficult. Processes such as Alkali Surfactant Polymer Flooding have been considered, however, the requirement of large amounts of fresh water as well as softening units in the field adversely affects the economics of this process.
This paper will discuss the development of a new anionic surfactant that provides solubility in high salinities and low interfacial tension at low concentration. The Chihuido de la Sierra Negra field history will be briefly described, and the laboratory screening and evaluation of the surfactants, including the interfacial tension properties, the adsorption, the core evaluation, and the performance of the flood will also be discussed.
The significance of this development is that it could lend feasibility to EOR projects that would be deemed uneconomical because of water treatment and handling costs.
A Circulating Foam Loop for Evaluating Foam at Conditions of Use
Authors: Hutchins Richard D. , Miller Matthew J. 
Published: December 2007

Abstract
Foam stability is an important parameter for foamed fracturing. Bench-top testing is useful for screening but does not address the necessary conditions of temperature, pressure, pH (particularly with carbon dioxide [CO2] systems) and dynamic flow conditions which can have unexpected influence on the foam's performance.
A laboratory apparatus has been constructed for measuring the rheology of circulating foam fluids to 400°F and 2000 psi. The apparatus is equipped with a circulation pump, view cells, foam generator, mass flowmeter and piping for loading a foam of the desired quality using either nitrogen or CO2. The foam rheometer is intended for evaluation of foam stability with time and comparison of various foam formulations for application in foam fracturing.
The foam loop was designed to mimic shear rates found in a fracture or reservoir, which are typically 200 s-1 or less. The rheology is measured by monitoring the pressure drop across a 20-ft length of ¼-in. tubing maintained at temperature in an oven. Flow rate is continually adjusted to ensure a constant shear rate in the tubing by the software using continuous mass flowmeter input.
Results relating to CO2 and nitrogen foams are discussed with emphasis on foam persistence, bubble size and population, and the rheological behavior with time. Temperature, pressure, and additives affect both foam texture and foam stability. The adoption of a standard technique patterned after this work for evaluating foam rheology could impact the use and development of foam fluids in the future.
Improved Transportation of Waxy Crude Oils and Emulsions in Bekasap Area, Indonesia
Authors: Tang Y. , Shuler P. J. , Cheug S. K. , Goodgame J. A. , Hsu J. J. , Padilla A. V. 
Published: December 2007

Abstract
One challenge in the production of oil fields in the remote Bekasap Area of Indonesia is the transportation of waxy crude oils through long pipelines. The current practice is to add hot water to the oil so fluids remain well above the pour point temperature of the crude (90 – 105 °F). This, however, limits oil-carrying capacity and increases costs due to handling and separating oil/water mixtures. This study focused on understanding the causes of the high pipeline pressures and to develop more economic transportation strategies. Laboratory measurements included oil/water emulsion rheology over a wide span of conditions, wax/gel formation, and the effect of various chemical treatment additives. A customized spreadsheet program was developed to model the current pipeline operation and to predict the change in pipeline pressures/temperatures under different scenarios.
The results indicate that the formation of relatively high viscosity oil/water emulsions is the most likely cause for the high pressure losses in these flowlines. Laboratory measurements demonstrate these oil/water mixtures have a complex physical nature and rheology. Simulations indicate the potential benefit of reducing the mixture viscosities via chemical treatment or heat management. For the Pinang Field, which was studied in the most detail, adding insulation to bare pipe areas provided a successful solution.
Removal of Water Soluble Organics from Produced Brine without Formation of Scale
Authors: Hart Paul R. 
Published: December 2007

Abstract
Water Soluble Organics (WSO) are included in the measurement of Oil and Grease (O&G), a conventional pollutant controlled by the Clean Water Act. WSO partition to the produced brine at the production pH but to the extraction solvent used to measure the O&G at the test pH of &lt; 2. The predominant chemical species comprising WSO in Gulf of Mexico crude oil brines are medium chain carboxylic acids. Chemicals can be added to desolubilize these species in conjunction with treatments to remove the resultant emulsion. For a variety of reasons, the most reliable and cost effective desolubilization agents have proven to be the non-volatile, multi-protic oxy acids (e.g. HxSOx and HxPOx). However, in the presence of divalent cations in the brine, these form insoluble scale deposits. Moreover, in the presence of WSO in mixed production, this scale becomes oil wet and uninhibitable. A new treatment comprising a new class of desolubilizer in conjunction with certain polymers has now been shown to be equally reliable and cost effective without the formation of scale even at extreme concentrations of divalent cations. The chemistry is explained and case histories chronicled to illustrate its effectiveness in the field.
Effect of Dispersion on Transport and Precipitation of Barium and Sulfate in Oil Reservoirs
Authors: Delshad Mojdeh , Pope Gary A. 
Published: December 2007

Abstract
The incompatibility of injected saline seawater and formation water is the primary cause of scale deposition in offshore developments. Many offshore oilfields are encountering problems with barium sulfate precipitation due to the mixing of sulfate-anion-rich seawater and formation brine with excessive amounts of barium cation. A mechanistic physico-chemical modeling approach is required to predict the amount of scaling to assist operators in making decision regarding scale prevention in oil reservoirs. The predictive model allows various types of flow scenarios to be investigated to reduce the amount of scaling and prevent well damage and eventual loss of well productivities.
Three-dimensional field-scale simulations were performed to investigate the flow and transport of barium and sulfate ions and the significance of barium sulfate precipitation in a typical offshore oil reservoir. The reservoir simulator has the modeling capability of multiphase flow, water reaction chemistry and interaction with the rock, and more significantly the species transport equations that include physical dispersion. The reactions were kept simple with barium and sulfate ions as the only reacting species and sodium, chloride, and calcium ions as non-reacting species. Barium sulfate was considered as the only solid precipitate. Simulations were performed to determine sensitivity to dispersion and mixing in the reservoir, to determine how much solid precipitates in the reservoir and in the wellbore, and to estimate how much sulfate needs to be removed from the injected seawater to prevent the formation damage.
The Impact of Chemical Incompatibilities in Commingled Fluids on the Efficiency of a Produced Water Reinjection System: A North Sea Example
Authors: Stalker Robert , Collins Ian R. , Graham Gordon M. 
Published: December 2007

Abstract
The current practice of overboard discharge of produced water from offshore facilities is becoming increasingly less attractive owing to environmental concerns and the impact of more stringent regulations. An alternative to overboard discharge is produced water re-injection (PWRI) into depleted reservoirs or into non-communicating aquifers. However, as offshore developments become more complex, with new fields producing through existing facilities, PWRI must face the problems involved in combining and re-injecting incompatible fluids and/or production chemicals. In this paper we describe a laboratory testing programme which was devised to aid in the development of a PWRI scheme for a North Sea facility. In the proposed re-injection scheme, produced waters from five fields are combined at a central facility prior to re-injection. Initial brine/production chemical compatibility tests identified potentially problematic incompatibilities. A series of formation damage core floods were performed to investigate the effect of these incompatibilities on injectivity into reconditioned reservoir core material from the proposed re-injection well. These tests were followed by further core flooding work in which alternative solvent-based strategies for the amelioration of incompatibility issues were investigated. From this sequence of tests emerged a PWRI protocol suitable for advancement towards field trials.
This paper describes typical problems encountered in the development of multi-well produced water re-injection projects using commingled waters produced from different fields containing potential incompatibilities both from the co-mingled brines themselves and also as a result of the diverse range of treatment chemicals present in the individual production streams. The strategies employed to overcome these problems in this field case are discussed.
Drag Reduction-Performance in Laboratory Compared to Pipelines
Authors: Hamouda A. A. 
Published: December 2007

Abstract
Flow assurance in pipelines is enhanced by the use of long chain polymers having average molecular weight of many orders of magnitude over 106. This makes them susceptible to shear degradation in oil pipeline systems, hence loss of performance. In order to be able to scale-up the drag reduction efficiency tests from laboratory to full-scale pipeline, it is important to design the laboratory test experiments to address pipeline parameters such as flow regime, shear rates, temperature and pressure changes. It is impossible to include All the parameters in one test, as the case for the actual pipeline systems where all these parameters are interacting simultaneously. However, designing experimental tests that make bridges between these parameters may offer a compromising solution(s) addressing certain conditions.
The work done in this paper is related to defining the major parameters and validates some of the used theories to establish the flow regime envelops. Prandtle Karmen theory and Virk's, maximum drag reduction asymptote are combined to define the onset envelops in transition from one regime to another in presence of the polymer drag reducers. A Three-process approach has been developed to evaluate the degradation in terms of rheological behavior and drag reduction efficiency. Some case studies are re-visited to explain some of the observations.
A Systematic Approach for Experimental Study of Asphaltene Deposition for an Abu Dhabi Reservoir Under WAG Development Plan
Authors: Negahban S. , Joshi N. , Jamaluddin A. K. M. , Nighswander J. 
Published: December 2007

Abstract
This paper discusses experimental work associated with the evaluation of asphaltene deposition for a field in Abu Dhabi, UAE. The subject reservoir is in the early stages of development and will be put on production using a combination of gas, water, and water aleternating gas (WAG) injection schemes in early 2006. The field has not shown operational problems resulting from asphaltene precipitation during primary production.
Laboratory experiments using the transmittance of an optimized laser light in the near infrared (NIR) wavelength (∼1,600 nm) were used to first confirm the stability of asphaltene in the reservoir fluid. Two cases, covering the expected extremes in terms of the field gas/oil-ratio (GOR) were evaluated. Isothermal depressurization tests were also conducted at reservoir, wellhead, and separator temperatures (250°, 190° and 130°C).
Several additional light transmittance experiments were conducted to evaluate the asphaltene instability regions resulting from reservoir fluid contact with various concentrations of a rich gas and carbon dioxide (CO2). Measurements using high-pressure filtration were also conducted to quantify the bulk precipitation of asphaltene with various molar concentrations of gas.
Finally, tests were conducted using state-of-the-art technologies to evaluate the consistency of the initial NIR runs. These technologies involved the use of a spectral analysis system (SAS) to evaluate the asphaltene particles size and growth rate and high-pressure microscopic images to visually confirm the measurements.
Results indicated that rich hydrocarbon gas, in contact with reservoir fluid, destabilizes asphaltene. The amount of the bulk precipitation increased with higher concentrations of rich gas in the reservoir fluid. Particle sizes were in the range of 0.5 to 1 micron and did not pose any threat to plug pore throats, and consequently did not affect the recovery potential. The effect of CO2 was found to be less severe with regards to asphaltene instability.