bluuebunny/crossref_metadata_2025_split huggingface dataset:
pH Sensitive Polymers for Novel Conformance Control and Polymerflood Applications
Authors: Choi Suk Kyoon , Sharma Mukul M. , Bryant Steven L. , Huh Chun 
Published: April 2009

Abstract
Novel conformance control and polymerflood applications that exploit the pH-sensitivity of partially hydrolyzed polyacrylamide (HPAM) are proposed. The key feature of this process is the injection of the HPAM solution under acidic conditions. The low pH makes polymer molecules coil tightly, resulting in a very low polymer solution viscosity. This allows the polymer solution to be injected into the reservoir at a substantially reduced injection pressure. Once injected, the acid reacts with the formation minerals to cause a spontaneous pH increase, uncoiling the polymer chains and causing a large increase in solution viscosity. Such a viscosity control scheme can be exploited for placement of a concentrated polymer solution in high-permeability zones, where it later viscosifies to divert subsequently injected fluids (in-depth conformance control), or to reduce the high pressure drop near the wellbore during polymer injection (injectivity improvement). Extensive rheological measurements and coreflood experiments (for different polymer molecular weights and degree of hydrolysis, and at different pH, salinity, and polymer concentration), are performed and interpretated.
Rheological measurements show that both shear and oscillatory viscosities of HPAM solution have a pronounced, but reversible, dependence on pH. Coreflood results show that the HPAM solution under acidic conditions can be propagated through cores with much higher mobility than at neutral pH. The use of a weak acid is the key. The peak pH's observed in several shut-ins guarantee that spontaneous geochemical reactions can return the polymer solution to its original high viscosity. However, low-pH conditions increase adsorption (polymer-loss) and require additional chemical cost (for acid). The optimum injection formulation (polymer concentration, injection pH) will depend on the specific reservoir mineralogy, permeability, salinity and injection conditions.
Laboratory Measurement of pH of Live Waters at High Temperatures and Pressures
Authors: Mathews S. G. , Raghuraman B. , Rosiere D. W. , Wei W. , Colacelli S. , Rehman H. A. 
Published: April 2009

Abstract
This paper describes a new technique for measuring pH on live formation water samples in the laboratory at high temperature and pressure. The technique involves adding pH sensitive dyes to pressurized single phase water samples collected using a formation tester and spectroscopically determining the pH in the laboratory at reservoir conditions. Water chemistry and pH are important inputs for scale and corrosion modeling. Due to the lack of standard laboratory techniques for such measurements at high temperatures and pressures, current practice involves flashing the single phase water sample, analyzing the flashed water and gas phases, and then using water chemistry models to predict pH at reservoir conditions. Uncertainties in the thermodynamic models for formation waters at high temperature and pressure, as well as uncertainties associated with the flash process and possible precipitation of salts, can propagate as errors into scale and corrosion models. It is proposed that the direct pH measurement on live water samples described here be used as an additional input for the water chemistry models to improve confidence in their predictions. This will allow for more efficient selection of completion materials and planning for scale treatment and mitigation.
In this paper, we present results of laboratory pH measurements on formation water samples from two offshore Gulf of Mexico wells for pressures to 20,000 psi and temperatures to 242°F. Results are compared to predictions from two commercial thermodynamic models that use the flashed gas and water analysis data as inputs. The setup can also measure the sensitivity of pH to pressure and temperature. Comparison of the laboratory pH measurement to real-time in situ downhole pH measurements made on the same formation water with a formation tester showed good agreement. This is an example of the implementation of the chain of custody concept, which compares a measurement made downhole with that made in the laboratory on the same sample using the same technique, to validate the representativeness of the sample as it is transported from downhole to the laboratory.
Evaluation of H2S Scavengers for Matrix-Acidizing Treatment
Authors: Xiao Z. , Morgenthaler L. N. , Cowan M. K. , Aremu K. , Adams J. G. 
Published: April 2009

Abstract
Operational reports indicate that a spike of H2S is sometimes evolved while flowing back the acidizing treatment. H2S is produced by the reactions between acid and sulfide scales. We investigate in this paper the performance of various H2S scavengers and deliver guidelines for field application of H2S scavengers in acid treatment of wells.
Five commercial H2S scavengers from chemical suppliers and service companies are evaluated under various conditions such as temperatures, acid-mineral ratios, and scavenger concentrations. Scavenger effects on reaction kinetics, acid dissolution capacity and scavenging capacity are investigated. Core flow tests, sequential spending tests, scavenger performance tests under field conditions, and compatibility tests were also performed to study scavenger effectiveness at various operation conditions and potential formation damage caused by spent scavengers.
In the tests reported here we identify one product that meets all our performance criteria, several that meet most performance criteria and several that meet few of our performance criteria for potential application to scavenge H2S in well acidizing fluids.
Reacting Ions Method to Identify Injected Water Fraction in Produced Brine
Authors: Ishkov Oleg , Mackay Eric , Sorbie Ken 
Published: April 2009

Abstract
Waterflooding is a very common method of oil displacement and pressure support. One particular problem that may arise after injection water (IW) breakthrough at the production well is the formation of sulphate scale. One of the main parameters that determines the severity of this type of scale formation is the amount of injection water/formation water (IW/FW) mixing that has taken place. Thus, the injected water fraction in the produced brine mix is an important value to determine. Our ability to model scale precipitation in situ and in the well is linked to our ability to accurately determine the IW fraction at production wells. Current industry practice is to work on an analytic approach for determining the fraction of IW in the produced brine stream in general, and for identifying IW breakthrough in particular.
A robust and accurate method for determining IW fraction in field produced water analysis is required to match the modelled IW fractions. When this is achieved, it is possible to use various modelling techniques with a higher degree of confidence to predict future scaling tendencies, and to help implement an appropriate scale management strategy to economically mitigate the potential effects of scale damage.
In this paper, the "Reacting Ions" method is introduced for determining the fraction of IW (and FW) in produced waters. This method is then applied to a synthetic produced water case where the "correct" answer is known, and a very good match is achieved, even when significant noise is applied to the synthetic data. The method is then applied in the analysis of produced brines for several wells in a North Sea field. Results of the study presented here show that the method is more effective in detecting IW fractions than conventional ion tracking techniques, especially at low IW fractions close to when breakthrough occurs. The significant new development presented in this work is that this approach may be used accurately even in situations where scale deposition deep in the reservoir impacts the concentrations of the ions used in this method.
Nonaggressive Matrix Stimulation Fluids for Simultaneous Stimulation of Heterogeneous Carbonate Formations
Authors: Wang Xiaolan , Qu Qi , Cutler Jennifer , Boles Joel L. 
Published: April 2009

Abstract
Two major challenges associated with conventional stimulation fluids are the corrosive nature of the fluids and their inability to treat the entire productive interval of heterogeneous formations without employing diversion techniques. It is often difficult to prevent corrosion on oilfield tubular from the conventional acid stimulation fluids, especially in high temperature wells. Additionally, when conventional acid is injected into a long heterogeneous formation, it preferentially enters intervals of least resistance or highest permeability. The injected acid continues reacting with formation material to further increase formation permeability thus ensuring acid intake into the same high perm zone. This thief-like behavior leads to inadequate stimulation of target low permeability or damaged zones. This is especially true for matrix treatments of long open-hole horizontal wells. Various diverting techniques such as ball sealers, foams, and polymer pills, have been used to ensure stimulation focusing on the areas requiring most treatment. Without proper removal mechanisms after stimulation treatment, however, diverting agents may even cause formation damage.
This paper highlights the development of a nonaggressive matrix stimulation fluid. The non-reactive nature of this fluid at ambient temperature allows it to penetrate both high and low perm zones proportionally in a long heterogeneous reservoir. The strong acid generated in-situ during shut-in can stimulate both zones simultaneously. With this new system, not only the diverting agents can be eliminated, but also the procedures become simplified and cost is reduced. Laboratory testing demonstrates that this new stimulation fluid system can treat the heterogeneous productive intervals with significant permeability contrast without using damaging diverting agents under various conditions. Laboratory corrosion tests validate the fluid's low corrosion on oilfield tubular at elevated temperatures. Stimulation efficiency of the new fluid over conventional acids on carbonate formations will be discussed to illustrate that the new fluid provides a better alternative in many situations.
Diversion and Propagation of Viscoelastic Surfactant Based Acid in Carbonate Cores
Authors: Al-Ghamdi Abdulwahab H. , Mahmoud Mohamed A. , Hill A. D. , Nasr-El-Din Hisham A. 
Published: April 2009

Abstract
Surfactants have been used over the past few years as a diverting material when mixed with acid solutions. Several papers are aimed to understand the overall process and the diversion capability. However, most of the coreflood experiments, if not all, used relatively short cores usually ranging between 2 to 6 inches in length and 1 to 1.5 inches in diameter. In this paper and for the first time, 20 inches long cores were used in conducting the acidizing experiments. The lithology of the rock type used was calcite, which has permeability of 50 to 120 md. In addition to the appropriate surfactant concentration, 15 wt% HCl was used. A key parameter such as flow rate, affects the behavior of the gelling material significantly. Therefore to capture that effect, flow rates chosen to be representative ranged between 5 and 15 cm3/min. A further analysis included is the effluent concentration for the mineral composition mainly Ca++. In addition, the acid concentration in the effluent was measured and validated with an analytical model to address the acid profile along the wormhole, which becomes an important aspect in understanding the flow of VES fluids in carbonate cores.
Part of this study is to characterize the wormhole propagation expected from the acidizing process. To accomplish this task, computerized tomography (CT) was used to generate 3-D images to describe the shape of the wormhole. There is a major difference in the shape of the wormhole when using the diverting material compared to conventional acids. The wormhole path observed in the first case tended to have several changes in direction as the acid tried to find its way to propagate further and avoid any possible blockage caused by the diverting material. This phenomenon would not be captured with short cores that were used in the previous studies.
Quantitative Analysis of an Amphoteric Surfactant in Acidizing Fluids and Coreflood Effluent
Authors: Yu M. , Mahmoud Mohamed A. , Nasr-El-Din H. A. 
Published: April 2009

Abstract
Viscoelastic surfactants (VES) exhibit remarkable viscoelastic character due to their ability of forming wormlike micelles and entangled structures, which can greatly increase the viscosity of the fluid. The VES fluids can be used to improve the proppant suspension ability and fluid diverting ability in well acidizing treatments. As a result, VES have been found numerous application in the oil fields as fracturing fluids and matrix acidizing fluids in the recent years.
According to previous studies, the concentration of VES in the fluids has profound effects on their performance downhole. Additionally, the loss of VES is also a very important indicator of the downhole events. Therefore, being able to analyze the concentration of VES surfactants in both live and spent acids is of great importance for production engineers who apply VES in the oil fields.
In the present work, a two-phase titration method was optimized for the quantitative analysis of a carboxybetaine viscoelastic surfactant, and the interference by typical additives in the acidizing fluids on this method was determined. This method was used in the determination of coreflood effluent, and it was found that tremendous amount of the viscoelastic surfactant is trapped in the core.
ab initio and Molecular Simulation Studies of Organic and Inorganic Counterions' Effect on Anionic Viscoelastic Surfactant
Authors: Sultan A. S. , Balbuena P. B. , Hill A. D. , Nasr-El-Din H. A. 
Published: April 2009

Abstract
Viscoelastic surfactants have a wide range of applications in the oilfield industry, including acid fracturing and matrix acidizing. A problem associated with acidizing is the tendency of the live acid or spend acid to form sludge which can reduce the effectiveness of the treatment or plug the formation or production equipments. Formation of sludge results from precipitation of insoluble materials upon interaction with acid. Presence of cations such as ferric will enhance the aggregation process. Emulsion and corrosion are other problems associated with well acidizing and it can impact flow to the wellbore. It has been reported that anionic surfactants can address some of the problems associated with well stimulation and align themselves due to intermolecular attraction or non-covalent bonds to form wormlike micelles. The micelles can be absorbed on the formation or further interact to form a network exhibiting elastic behavior dependent on type of rocks. This increase in viscoelasticity helps in many cases to control fluid placement while acidizing multiple zones with variation in permeability and it also has sufficient properties to suspend and carry the proppant into the fractured zone. Several previous experimental studies highlighted the significant role of counterions in determining the apparent properties of aqueous solutions that contained viscoelastic surfactants. Wormlike micelles are formed by aggregation of amphiphiles. Presence of co-surfactant, additives, salts or appropriate counterions helps promote growth of such micelles. The effect of counterions can be detrimental on the properties of the whole system. Understanding how macroscopic properties depend on intermolecular interactions for complex fluids is the main focus of this study.
Density functional theory and molecular dynamics simulations are employed to better understand how organic and inorganic counterions can impact physical properties of viscoelastic surfactants and hence their functionality in carbonate reservoirs. Anionic surfactants with different head groups include acetic acid (AA), potassium butanoate (PB) and sodium butane-1-sulfonate (S1BS), together with their counterions are simulated over a wide range of parameters. Competition between mono-, di- and trivalent counterions was studied in the gas phase of three anionic surfactant head groups with organic counterions (sodium salicylate, NaSal, and sodium hydroxynaphthalene carboxylate, NaHNC) and inorganic counterions (Na+, Mg2+, Ca2+, Fe2+ and Fe3+). Binding energy and thermodynamic properties show that trivalent counterions are more strongly bonded than di- and monovalent ones. The results give important insight into the links between molecular structure of surfactant and ions present in solution, which will help in developing more systematic procedures for treatment optimization, and better design of more efficient/effective viscoelastic diverting systems.
Biodegradable Alternatives for Scale Control in Oilfield Applications
Authors: Holt Stuart , Sanders Jannifer , Rodrigues Klin , Vanderhoof Matthew 
Published: April 2009

Abstract
Environmental legislation has significantly reduced the variety of scale inhibitor chemistries that can be used to prevent inorganic scale formation during the production and separation of crude oil from produced water. Poor ecotoxicity has severely impeded the use of phosphonates, while many polymers, the other traditional approach to scale control, fail to meet minimum biodegradation requirements.
We have developed biopolymers based on synthetic/natural polymer hybrids that show enhanced biodegradation, are environmentally benign and are much less reliant on non-renewable monomer feedstocks than classical polymer scale inhibitors. As well as being more sustainable, this novel technology allows the inclusion of a broad range of functional groups that can be designed to meet the varying technical demands of oilfield scale inhibitor application environments.
Various hybrid polymers have shown excellent performance under standard oilfield performance testing conditions versus a range of currently used chemistries. Some distinct benefits of hybrid technologies pertaining to oilfield scale control will also be expanded upon.
Effect of Salinity on Wettability Alteration of Porous Media From Liquid Wetting to Intermediate Gas Wetting
Authors: Wu Stanley , Firoozabadi Abbas 
Published: April 2009

Abstract
The synergetic effect of salinity and fluorochemicals on the alteration of wettability from water-wetting to intermediate gas-wetting is studied in this work. We find that NaCl salinity increases water-wetting when a core is saturated with brine. NaCl also reduces absolute gas permeability as reported in the literature. CaCl2 salinity is drastically different from NaCl brine, and has a minor effect on permeability. The NaCl, KCl and CaCl2 brines have an adverse effect on wettability alteration. To alleviate the effect of salt on treatment, we suggest pre-treatment by displacement of brine with water and subsequent drainage by nitrogen.
Review and Evaluation of Corrosion Inhibitors Used in Well Stimulation
Authors: Rostami A. , Nasr-El-Din H. A. 
Published: April 2009

Abstract
Corrosion inhibitors are an indispensable part of the fluid mix pumped downhole when a well is acidized. Of the various approaches to mitigate corrosion, the best way to reduce corrosion problems in the petroleum industry is to use corrosion inhibitors. Determining the most effective corrosion inhibitor for a given environment is essential.
There are enormous examples of chemical inhibitors, which are propriety mixtures of several chemicals to induce synergistic effect. But basic function of corrosion inhibitors is by using some organic compounds containing oxygen, sulfur and nitrogen. This paper gives a complete vision of what the corrosion inhibitor is. How the structure of corrosion inhibitor molecule can affect the functionality of these molecules. This work discusses the effect of factors like chain length, degree of branching, substitution of multiple for single bond, using sulfur instead of nitrogen and other factors that affect the efficiency of corrosion inhibitor molecules. Depending on the mechanism of corrosion mitigation, corrosion inhibitors are classified as cathodic inhibitors, anodic inhibitors and mixed inhibitors which are explained in the paper.
Corrosion inhibitors used in well stimulation acidizing are organic molecules, usually film-forming amines. They are classified as mixed inhibitors that affect both cathodic and anodic reactions and will decrease corrosion rates. Their effectiveness is largely a function of their ability to adsorb at the metal/metal-oxide surface. Adsorption occurs due to the polar or charge nature of organic molecules/ionic species first establishing a physisorbed surface film (through Vander walls forces), which may further stabilize through chemisorption to form a donor-type bond. This paper discusses and compares the performance of various corrosion inhibitors and intensifiers, addresses limitations of each inhibitor and give recommendations for field application.
New Insights into the Viscosity of Polymer-Based In-Situ Gelled Acids
Authors: Gomaa A. M. , Nasr-El-Din H. A. 
Published: April 2009

Abstract
Diversion techniques must be employed to remove all the damage from the entire producing interval. Diversion in carbonates is more difficult than in sandstones because of the ability of acid to significantly increase the permeability in carbonates as it reacts in the pore spaces and flow channels of matrix. The apparent viscosity of the in situ gelled acid based on polymer plays a key role in diversion because it creates a viscosity differential in treated and untreated zones. An extensive literature survey and field data, there is no agreement on the effectiveness of this acid system. Therefore , this study was conducted to better understand this acid system and determine factors that impact its viscosity build-up. Three commercially available in-situ acids were examined.
The effect of salts, iron contamination on the apparent viscosity of these acids was examined. Several new findings were identified, including: Polymer and other additives were separated out of the acid when these acids were prepared in high salinity water. Preparing the in-situ gelled acid with saline water decreased the viscosity of the acid in live and neutralized conditions. Concentrated HCl solutions produced high concentrations of calcium chloride that reduced the viscosity of the acid system. Therefore, in-situ gelled acids that are based on the polymer should be used at low HCl concentrations (3-5 wt% HCl). Sodium, calcium or ferric chlorides reduced the apparent viscosity of live acids. A brown precipitate was noted during the neutralization of acid systems that contained Fe(III) even in the presence of the recommend concentration of iron control agents.