bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Polymer Chemistry for Squeeze Application in Tight Carbonate Reservoirs
Authors: Chen Tao , Heath Steve , Benvie Ronald , Chen Ping , Montgomerie Harry , Hagen Thomas 
Published: May 2012

Abstract
The development of effective scale squeeze inhibitors in carbonate reservoirs is still a big challenge, especially with the increasing environmental constraints. For tight carbonate reservoirs, formation damage is one of the major considerations as it can be caused due to fines mobilization, carbonate reservoir dissolution and collapse, and scale inhibitor compatibility issues. For the development of any product for squeeze application, the product must also demonstrate good inhibition performance, long squeeze life and accurate residual analysis at low concentrations as well as being suitable for improved placement techniques if required.
Many scale inhibitors are either irreversibly retained in chalk reservoirs due to uncontrolled precipitation reactions or are poorly adsorbed with both processes resulting in short treatment lifetimes. Some new, readily detectable, polymeric scale inhibitor chemistry, containing a special functional amine group to have a good affinity to the chalk reservoir, was developed to provide a balance between irreversible and poor retention and thus provide effective squeeze life.
The results of a comprehensive testing program, including compatibility, formation dissolution, dynamic tubing blocking, static adsorption and core flood tests will be presented, that will highlight the design and development of a polymeric scale inhibitor suitable for tight carbonate reservoirs while meeting the environmental requirements for application in the UK and Scandinavia.
The new polymer has been shown to demonstrate excellent retention and release characteristics while also being non-damaging to carbonate reservoir material. The impact of calcium tolerance, pH and molecular chemistry will be discussed with regard to the design and performance of the new polymer when compared to some environmentally friendly phosphonate chemistry and other polymeric scale inhibitors.
This paper will demonstrate a logical design procedure to develop an environmentally acceptable polymeric scale inhibitor product whose chemistry has been optimised for squeeze application in tight carbonate reservoirs. In addition, discussions on the mechanisms of scale inhibitor retention and formation damage with regard to selection, design and optimization of suitable scale squeeze inhibitors in tight carbonate reservoirs will be addressed.
Elemental Sulphur Induced Formation Damage Management in Gas Reservoir
Authors: Adesina Fadairo , Churchill Ako , Olugbenga Falode 
Published: May 2012

Abstract
Sulphur compounds are considered as the most hazardous non-hydrocarbons in reservoir fluids, because of their corrosive nature, deleterious effects of petroleum products and tendency to plug porous medium which may impair formation productivity. Precipitation and deposition of elemental sulphur within reservoirs, near well bore region may significantly reduce the inflow performance of sour-gas wells and thus affect economic feasibility negatively.
Studies have sought that almost all deep sour reservoirs precipitate elemental sulphur either occurring as a result of decomposition of H2S to give elemental sulphur or occurring as indigenous usually referred to as native sulphur as a dissolved species. Uncontrollable elemental sulphur induced formation damage has been one of the profit hurting syndromes that occurs in deep water sour gas reservoir.
Meanwhile many correlations have been formulated thermodynamically to predict the occurrences of elemental sulphur but little information related to effect of its saturation on gas production and its corresponding formation damage.
This paper presents an improved model for predicting elemental sulphur saturation and corresponding formation damage around the well bore. Results show that the minimum pore spaces blockage time was over-estimated by previous formulation.
Effects of Hydrate Inhibitors on the Solubility of Barite and Halite in Produced Water
Authors: Djamali Essmaiil , Lu Haiping , Kan Amy T. , Tomson Mason B. 
Published: May 2012

Abstract
Large quantities of hydrate inhibitors, such as methanol, MEG (ethane 1, 2 diol), and TEG (triethylene glycol) are used to prevent gas hydrate formation during production from a gas/oil well. Due to environmental and economic concerns, MEG is often regenerated via a thermal vacuum distillation process. The hydrate inhibitors adversely enhance scale formation. The impact of temperature and concentration on mineral scale formation during MEG regeneration is largely unknown. The solubility of barite and halite in methanol/brine and MEG/brine solution was measured up to 473.15 K (200 °C ) and 6.6 MPa (1000 psia) to evaluate the impact of high temperature on mineral scale formation in hydrate inhibitor/brine solutions. A model is developed to assist the process design to prevent scaling risk during MEG regeneration. The "unified theory" of electrolytes developed by one of the authors (EDJ), for prediction of the standard state thermodynamics properties of electrolytes to extreme temperatures and pressures, has been adapted to model the effect of temperature and pressure on mineral salt solubility in methanol, ethanol and MEG/brine solutions. The model requires knowing the Gibbs free energy of hydration at some temperature, usually 298.15 K (25 °C), and only two previously determined constants for each electrolyte. Once these constants are fixed, the model can be used to predict the standard state partial molar Gibbs free energies of electrolytes up to supercritical temperatures. The temperature and pressure behavior of electrolytes can now be accurately predicted from existing low temperature data alone. A modification of Pitzer's model for activity coefficients is also used to account for the effect of mixed electrolytes on solubility in cosolvent/brine systems. The combined model will be applied to typical reboiler systems in use on off-shore platforms and on shore.
A Novel and Comprehensive Study of Polymeric and Traditional Phosphonate Inhibitors for High Temperature Scale Control
Authors: Wang Wei , Kan Amy T. , Tomson Mason B. 
Published: May 2012

Abstract
This paper presents a quantitative study of scale inhibitor thermal stability with regard to their potential application in high temperature wells. Systematic experiments have been conducted to investigate: (1) the influence of thermal aging on phosphonate and polymeric inhibitors at 200 °C, (2) the time (minutes to days) and temperature (up to 200 °C) dependence of inhibitor thermal degradation, (3) the impact of stainless steel and iron on the degradation of inhibitors at high temperatures, (4) the difference in aging tests with inhibitors in solution and that adsorbed on core materials, and (5) the effectiveness of a chelating agent to prevent the catalytic degradation of scale inhibitor by metal ions. The results enable a more accurate understanding of thermal degradation and provide a comprehensive guidance on the selection and placement of scale inhibitors for high temperature oil and gas production.
Coupled Adsorption/Precipitation Experiments: 2. Non-Equilibrium Sand Pack Treatments
Authors: Ibrahim J. , Sorbie K. S. , Boak L. S. 
Published: May 2012

Abstract
Scale inhibitors (SI) are retained in the reservoir formation by both adsorption (Γ) and precipitation (Π) mechanisms, and these are responsible for the duration of the squeeze lifetime. However, processes such as the adsorption of SI and dissolution of precipitated SI complexes are not instantaneous. During a scale inhibitor treatment in a rock core, the fluid/mineral contact time may be quite short compared to the equilibrium time for the SI/mineral system for many practical experimental flow rates. This is also the case in the near-wellbore region where flow rates are very high and hence dynamic (non-equilibrium) effects may be significant. The SI retention process occurring in the sand packs, and indeed within the reservoir formation, are therefore likely to be non-equilibrium processes for at least some period of the squeeze process. If this hypothesis is correct, non-equilibrium behavior can be observed from the change in observed SI effluent concentrations as the flow rate changes in the sand pack flood. Therefore, non-equilibrium effects must be taken into account in the derivation of the parameters governing the squeeze such as the adsorption isotherms and/or the precipitation/dissolution model.
In this paper, we present a range of novel experimental results from a series of variable rate adsorption and precipitation sand pack floods for OMTHP ( hexaphosphonate) scale inhibitor. The sand pack experiments were conducted using silica sand as the adsorbing mineral and all the floods were conducted using identical procedures. The unique feature of this series of floods is that the bulk coupled adsorption/precipitation behaviour of this system (OMTHP/sand) has been fully characterized in previous work (Paper 1, Ibrahim et al., 2012). Therefore, we know precisely when the system is in the "adsorption only (Γ)" or in the "coupled adsorption/precipitation (Γ/Π)" regime. The sand pack effluent results show non-equilibrium behavior as the flow rate changes. These results indicate the importance of flow rate on the derivation of dynamic isotherms (Γ) and precipitation models (Π) prior to field application modeling. We believe that the results presented in this work probably yield the most complete dataset of well characterised adsorption/precipitation SI pack floods assembled to date.
The Relation Between Barite Inhibition by Phosphonate Scale Inhibitors and the Structures of Phosphonate-Metal Complexes
Authors: Shaw S. S. , Welton T. D. , Sorbie K. S. 
Published: May 2012

Abstract
In produced waters from fields undergoing seawater (SW) flooding, inhibiting mineral scaling can be problematic because the SW/formation water (FW) ratio is constantly changing. For barium-sulfate scale, for example, the barite saturation ratio (SR), the yield of barite precipitate, and the molar ratio Ca2+/Mg2+ in the produced waters all evolve over time. This paper describes the effects of SR and molar ratio Ca2+/Mg2+ on the barium-sulfate inhibition efficiency (IE) of nine phosphonate scale inhibitors (SIs): OMTHP (hexa-phosphonate), DETPMP and HMTPMP (penta-phosphonates), HMDP and EDTMPA (tetra-phosphonates), NTP (tri-phosphonate), EABMPA and HEDP (di-phosphonates), and HPAA (mono-phosphonate and mono-carboxylate). IE experiments were carried out testing a range of SW/FW compositions (i.e., SR and molar ratio Ca2+/Mg2+ varying). The minimum inhibitor concentration (MIC) level of these phosphonate SIs might correlate with either the level of SR for the SW/FW mixing ratio in question (Type 1) or the Ca2+ and Mg2+ levels in solution (Type 2).
When experiments were repeated, but the produced brine molar ratio Ca2+/Mg2+ was fixed, the MIC for both Type 1 and Type 2 species always correlated with the SR. The performance of these phosphonate SIs in consumption experiments, where supernatant [SI] and [Ba2+] are both assayed by inductively coupled plasma (ICP) spectroscopy at multiple residence times, is also briefly discussed. In this paper, the reasons behind Type 1 and Type 2 IE behavior in phosphonate SIs are discussed, in terms of SI molecular structure, pH, SI speciation, SI binding constants to Ca2+ and Mg2+ cations, and the possible mononuclear or polynuclear chelate structures with M2+ cations that can form under the test conditions. Possible SI-M2+ complex structures are proposed, and through molecular modeling, explanations are provided for why Type 1 and Type 2 behavior is exhibited by phosphonate SIs.
Prediction of Mineral Scaling in a MEG Loop System of a Gas Production Offshore
Authors: Baraka-Lokmane S. , Hurtevent C. , Ohanessian J-L. , Rousseau G. , Seiersten M. , Deshmush S. 
Published: May 2012

Abstract
An offshore gas field located in the Far East has two reservoirs: reservoir A and reservoir B. Production fluids consist of gas and hydrocarbon condensate with some produced water from the two reservoirs. The producing fields are in water depths varying between 250 and 275m with ambient seawater temperatures and operating conditions that result in only occasional concerns about potential hydrate formation in the production systems. Lean Monoethylene Gylcol (MEG) is injected near the wellheads for hydrate inhibition.
This paper presents the risk of mineral scaling at critical points throughout the process with the three production scenarios: reservoir A alone, reservoir A and reservoir B, and finally reservoir B alone. Special attention has been put on the effect of mixing produced waters from reservoir A and reservoir B topside. Furthermore there are considerable uncertainties with respect to the amount of organic acids that may be produced; therefore some evaluations have been performed with and without organic acids.
Emerging 4th Generation Analytical Technology for the Individual Analysis of Multiple Families of Co-mingled Scale Inhibitors in Deepwater Wells
Authors: Thompson Alan , Gundersen Thomas E. , Andresen Alf Terje , Dahlgren Per Anders , Juliussen Bjorn 
Published: May 2012

ABSTRACT
The individual analysis of polymeric scale inhibitors in co-mingled flow backs from wells in subsea and deepwater templates is a particularly challenging application for analytical techniques in the industry.
The application of the analytical technique of mass spectrometry to this challenge has resulted in routine 3rd generational analytical methods where a primary inhibitor can be quantified in the presence of a secondary subsea squeeze inhibitor and a tertiary topside scale inhibitor; something which had not been demonstrated previously in commercial applications. In more complex deep water field developments in the North Sea and Gulf of Mexico, where 4–8 wells can be co-mingled, the use of these third generation analytical techniques may not always be sufficient therefore it is necessary to develop improved methodologies to cope with the presence of an increasing number of chemical families.
This paper presents details of an emerging 4th generation analytical method which is being developed to allow the accurate quantification of 4–5 chemical families of scale inhibiting polymers in the presence of each other and other production chemicals such as corrosion and hydrate inhibitors. These would include scale squeeze polymers, scale inhibiting polymers applied subsea, or scale inhibiting polymers applied topsides. This method builds upon the 3rd generation analytical technology by using a novel mass detection technique which gives a much enhanced sensitivity and specificity to molecular functional groups.
The development of this method will add to the rich "toolbox" of state-of-the-art analytical techniques which now allow the analyst an unparalleled ability to generate accurate, specific and robust data from even the most demanding of applications and allow the chemical supplier and operator to individually monitor wells tied back to even the most complex of subsea templates in the most challenging of deepwater applications.
Selection of Anti-scale and Anti-corrosion Products: How to Avoid Interactions?
Authors: Gonzalez Marianna Rondon , Passade-Boupat Nicolas , Bascoul Paul , Baraka-Lokmane Salima , Hurtevent Christian 
Published: May 2012

Abstract
The injection of multiple chemicals, such as anti-scale and anti-corrosion additives, must often take place sequentially or simultaneously in very close injection points. Thus it is necessary not only to evaluate the efficiency of chemicals individually, but also to screen for incompatibilities and/or interference between chemicals. These interferences can affect either the anti-scale efficiency, the anti-corrosion efficiency, or even worth both additives efficiencies at the same time. This kind of mutual reduction of efficiency may have been the reason for past pipeline failures, where both scaling and corrosion were observed despite the addition of large quantities of both additives. Electrostatic interaction is a possible explanation, as the two chemicals carry opposite charges. In conjunction with the usual tests performed for additive selection, a physicochemical framework has been developed to evaluate the behavior of pairs of additives at different concentrations. For a model water presenting both corrosion and scaling issues, the efficiency of the anti-scaling additive is evaluated based on the quantification of free Ba2+ in solution by ionic chromatography and the efficiency of the anti-corrosion additive is assessed based on the change in the interfacial tension. Many candidate additives for oil field applications have been evaluated and "interaction maps" have been constructed. These maps indicate regions of concentrations at which one or both additives are not effective. These maps are useful for the selection of products that should be effective without risks of interactions. To finalize the validation, we can perform an "ultimate" blocking test where both additives, water and oil, are in contact at one point of the experiment, to also take into account the partitioning of additive between oil and water. This framework is not only useful for production chemistry studies of new field developments, but also for new product tenders in existing fields.
A 3-Year Results of Application a Combined Scale Inhibition and Hydraulic Fracturing Treatments using a Novel Hydraulic Fracturing Fluid, Russia
Authors: Levanyuk Olesya , Overin Alexander , Sadykov Almaz , Parkhonyuk Sergey , Lungwitz Bernhard , Enkababian Philippe , Klimov Alexander , Energy Imperial , Legeza Sergey 
Published: May 2012

Abstract
Scale deposits are a common problem in oil and gas wells and can have detrimental effects on well production. Depending on the severity, scaling can stop production entirely as scale forms anywhere in the well production system, including the formation, perforations, casing or tubular, and in or on the artificial lift equipment. There are several chemical and mechanical methods for removing scale deposits. However, to prevent scale deposition, the only solution is chemical inhibitors injected into the formation. The typical production system includes artificially lifted, stimulated wells (propped hydraulic fractures) placed in reservoirs where pressure maintenance is achieved by water flooding. The artificial lifting is typically accomplished through use of electric submersible pumps (ESPs). In reservoirs where produced fluids exhibit scaling tendencies, ESP run life is significantly shortened by scale formation on the pump elements restricting rotation. By treating the formation with chemical inhibitors, the life of the ESP can be extended.
In this paper we provide approaches for improving a compatibility of a novel hydraulic fracturing fluid (used in Russia) and scale inhibitor. A 3-year campaign to combine scale inhibition with the hydraulic propped fracture effectively increased the average run life of ESPs in the Mayskoe and Snezhnoe oil fields.
Scale Removal Operations in High Pressure High Temperature Tight Carbonate Reservoir and Sour Environment - Challenges and Guidelines
Authors: Almai Noura , Dashti Qasim , Baddula Ravi Chandra , Al-Awadi Mishari , Baloushi Taha , Aouchar Najet , Hamed-Naji Iyad , Metzger Thomas 
Published: May 2012

Abstract
Currently, Kuwait Oil Company (KOC) is successfully producing from high pressure and high temperature formations. The reservoirs are deep with True Vertical Depth (TVD) approximating 15,000 feet, and pressures and temperatures of 11,000 psi and 275° F respectively. The formations are composed of carbonates both tight and porous. The produced hydrocarbons are of high H2S and CO2 content, up to 10% and 12%, respectively.
The aforementioned sour environment in addition to water cut occurrence during the production phase have led to scale creation. In addition, corrosion, erosion and pitting also occur, requiring well intervention to sustain production. Furthermore, well monitoring is essential and planning for workover and well interventions is becoming unconventional with higher associated risk.
The recent scale removal activities proved to be very challenging with weight loss seen from the coiled tubing (CT) of approximately 7,000 Ib and CT leakage while operating at the hole condition. The CT pressure control equipment failed due to sudden increased in H2S concentration, which was attributed to the chemical reaction between the cleaning fluid (15% HCl) and the well fluids/scale mixture.
This paper explains the well history, objectives of operation, execution history, procedures and causes of these challenges. Hence, lessons learned, observations and knowledge gained by the Kuwait Oil Company (KOC) are evolving, advancing, and being employed at an accelerated rate despite high cost.
Development of Test Method and Environmentally Acceptable Inhibitors for Zinc Sulfide Deposited in Oil and Gas Fields
Authors: Wang Bin , Chen Tao , Chen Ping , Montgomerie Harry , Hagen Thomas , Liu Xuan , Yang Xu 
Published: May 2012

Abstract
Zinc sulfide (ZnS) is an exotic scale formed in the oil and gas fields, especially in HT/HP wells. It is relatively difficult to test ZnS formation and inhibition in the laboratory using traditional static jar and dynamic loop tests due to the oxidization during the test and its naturally ‘soft’ scale characteristic. Limited studies have been focused on ZnS and the detailed inhibition mechanisms are still unknown.
In this paper, a newly developed stress test method has been applied to evaluate the performance and mechanisms of ZnS inhibition. Compared with the traditional test methods, it shows good reproducibility and provides a quick and effective way to evaluate the performance of inhibitors and information to understand the mechanisms of inhibition.
More than 15 typical scale inhibitors, representing several different types, have been tested using this newly developed method. The ZnS scale inhibitors were classified as three types based on the inhibition mechanisms from this work:
Type 1: Dispersion and nucleation inhibitors. These scale inhibitors showed nucleation and growth inhibition effect at low concentrations of sulfide and dispersion effect at high concentrations of sulfide.
Type 2: Nucleation and growth scale inhibitors. These scale inhibitors inhibit nucleation and growth of ZnS formation, where the test can be stressed further.
Type 3: Scale inhibitors with poor performance on ZnS inhibition. The turbidity and stress curve did not change obviously in the presence of scale inhibitors.
This paper will give a comprehensive study of ZnS formation and inhibition, including scale prediction, development of test method and inhibitors, insight into the mechanism of ZnS inhibition and identification of environmentally acceptable inhibitors.