bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New In-Situ Generated Acid System for Carbonate Dissolution in Sandstone and Carbonate Reservoirs
Authors: Sokhanvarian Khatere , Pummarapanthu Thanakrich , Arslan Emre , Nasr-El-Din Hisham A. , Shimek Nicole , Smith Kern 
Published: March 2017

Abstract
Matrix acidizing has long been used for permeability and productivity enhancement purposes in oil and gas wells. In sandstone reservoirs, a preflush is needed to dissolve carbonate minerals so that HF is not consumed in the main step on carbonate minerals. The preflush step also prevents the potential precipitation of the reaction products of HF. HCl has been an important component in preflush; however, it has high corrosion and reaction rates, especially in high pressure/high-temperature (HP/HT) wells. An acidizing system that is comparable to HCl in terms of availability and price is needed; however, the shortcomings associated with HCl, such as its fast reaction rate and high corrosion rate, must be addressed in the development of similar systems. Therefore, this study investigates the effectiveness of a new in-situ generated HCl acid that offers a slower reaction and corrosion rate in high-temperature reservoirs.
The new in-situ generated HCl acid treatment was used to acidize two types of sandstone cores (Grey Berea and Bandera) and two type of carbonate cores (limestone and dolomite). X-Ray Diffraction (XRD) analysis was performed on the sandstone cores to determine the mineralogy to design a better treatment. Coreflood experiments were conducted at 250 and 300°F to study the impact of the treatment on the permeability of sandstone cores. Acid injection rates were set at 1 and 5 cm3/min in the case of the sandstone treatments and 1 and 2 cm3/min for the carbonate stimulation. The effluent samples were collected every quarter pore volume to further analyze the ability of acid to dissolve carbonate and oxide minerals. Porosity profiles and wormhole propagation were determined before and after acid treatment using Computed Tomography (CT) scans.
Superior stimulation results were achieved at 250 and 300°F with the in-situ generated acid system. However, 15 wt% regular HCl caused 79% damage to the Berea core at 300. The new acid system resulted in positive stimulation results (kf/ki ranging from 1.7 to 2.7) in both Grey Berea and Bandera sandstone cores without any sign of fines migration or sand deconsolidation. In the case of carbonate stimulation, more PV of acid was needed to reach breakthrough if 15 wt% regular HCl was used as a treatment fluid. The wormhole propagation was more efficient in the case of the new acid system. Face dissolution was observed when using 15 wt% regular HCl in carbonate acidizing. The corrosion rate of low-carbon steel (L-80 and C-95) and chrome-based tubular (Cr-13) was significantly less than that noted with 15 wt% regular HCl at 300.
This study will assist in developing a more cost-effective and efficient design of acid treatments with minimal impact to the formation's integrity. This new in-situ generated acid system efficiently removes carbonate and oxide minerals in HP/HT sandstone reservoirs.
Unique Mixtures of Anionic/Cationic Surfactants: A New Approach to Enhance Surfactant Performance in Liquids-Rich Shale Reservoirs
Authors: He Kai , Xu Liang 
Published: March 2017

Abstract
Surfactants are important components in fracturing fluids for helping ensure higher productivity from unconventional reservoirs. Conventional wisdom suggests that surfactant mixtures generally exhibit better performance than individual surfactants. Additionally, the synergism between surfactants increases with the degree of charge difference. Some current commercial surfactants were formulated by mixing nonionic and anionic surfactants (Sn/a), but few were formulated by mixing cationic and anionic (Sa/c) surfactants because of the risk of precipitation or formulation instability.
This paper discusses binary mixtures of Sa/c surfactants prepared with different mole ratios to determine their synergisms; mixtures of nonionic/anionic (Sn/a) and nonionic/cationic (Sn/c) surfactants are also compared. Surface/interfacial properties [maximum surface excess concentration (Γmax), minimum molecular area (Amin), critical micelle concentrations (CMC), and Gibbs free energy (ΔG)] and interaction parameters (βm and βs) in both the mixed micelle and interface were quantified to demonstrate the synergistic effect between various surfactants. Additionally, the potential application of these mixtures for unconventional treatments was examined with regards to emulsion behavior and column-packed oil recovery testing.
The results for the Sa/c surfactant mixtures show that, compared to parent species, Γmax of the Sa/c system is approximately one order of magnitude higher (corresponding to one order of magnitude lower in Amin). The resultant CMC is approximately two orders of magnitude lower than the parent species, and the ΔG of Sa/c is more negative. Notably, the interaction parameters further indicate that strong synergism exists for the Sa/c system at various mole ratios in both mixed micelle and monolayers at the interface (with an optimized ratio at 2/3), while, for the Sn/a system, weak synergism was identified in the mixed micelle at the mole ratio of 3/2. No synergism was observed for the Sn/c system.
Additionally, phase behavior testing indicated that a weak emulsion was formed in the presence of the Sa/c using Eagle Ford crude oil. Column-flooding testing also revealed improved oil recovery of the Sa/c system compared to individual species. The synergistic effect between Sa/c surfactant mixtures, as well as the laboratory results of the emulsion behavior and oil recovery, suggests a new practice for applying Sa/c surfactant blends for unconventional applications.
A Novel Solid Inhibitor for Anhydrite Scale Control Under Extreme Well Conditions
Authors: Shen Dong , Bhaduri Sumit , Vo Minh , Carman Paul , Gupta D. V. , Pandey Yash 
Published: March 2017

Abstract
The formation and deposition of mineral scale can detrimentally impact production rates and affect the overall well performance during oil and gas production. This is especially challenging in HTHP stimulation treatments where compatibility of the scale control chemical with fracturing fluids is critical, and longer-term inhibition performance is desired. A new solid inhibitor was developed for this purpose and applied in multiple wells in the Eastern offshore basin of India to combat mineral scale within the proppant pack and production tubing over the long term, under extreme downhole conditions (T= 400°F, P=13,500 psi). Neither downhole chemical injection mandrels nor surface treatments can adequately control scale deposition under these conditions, spurring the need for a longer-term inhibition program for these wells.
A liquid scale inhibitor with excellent inhibition performance and good compatibility with various fracturing fluid systems at high temperature was first identified. The new solid inhibitor product was made by adsorbing the scale inhibitor onto a high-strength, proppant-sized substrate with a large surface area. The substrate is synthesized using nanotechnology, to prevent any possible conductivity loss under high formation closure pressure. Various chemical modifications were made to this adsorbed solid inhibitor to prevent excessive inhibitor release during early stages of production, resulting in a longer-term scale protection. This modification allows the solid inhibitor product to be completely compatible with the fracturing fluid.
Scale modelling indicates that the wells treated have a severe anhydrite scale problem under downhole conditions. The results of comprehensive laboratory testing show the new solid inhibitor can prevent anhydrite scale up to 400°F, and is completely compatible with zirconium- crosslinked fracturing fluid at 350°F and above. To date, six fracture treatments have been performed by using a total 23,800 lbs of this new solid inhibitor. The wellhead water samples are being collected for scale inhibitor residuals analysis, as the wells start to produce water. The residuals data review and comparison with laboratory-derived data are discussed in this paper.
Adding scale inhibitors to a fracturing fluid has been a well-established practice to provide long-term inhibitor protection during hydrocarbon production. However, to ensure compatibility of the inhibitors with high-temperature fracturing fluids, especially metal based cross-linked fracturing fluids, without compromising the inhibition longevity at high pressure and temperature remains a stiff challenge. The new approach described here meets this objective, extending the long-term well performance under HTHP conditions.
Matrix Acidizing of Carbonate Rocks Using New Mixtures of HCl/Methanesulfonic Acid
Authors: Kankaria Sneha , Nasr-El-Din Hisham A. , Rimassa Shawn 
Published: March 2017

Abstract
Successful matrix acidizing of carbonate reservoirs depends on the selection of optimal stimulation fluids. Because of the rapid reaction rate and corrosive nature of HCl in downhole conditions, other alternatives are much in demand. Organic acids, particularly methanesulfonic acid (MSA), offer a viable alternative to HCl in terms of being less reactive as well as less corrosive and environmentally benign. However, MSA is expensive. To reduce the cost, this study proposes to use blend of HCl and MSA for carbonate stimulation, while enhancing the properties of HCl. Coreflood studies were performed and the results were compared to those obtained by equivalent concentrations of the individual acids.
Three different ratios of HCl and MSA were used to conduct coreflood experiments on 6-in. long Indiana Limestone cores at 250°F. The volume of acid required to reach breakthrough was recorded, and the cores were analyzed using CT scans. Wormhole structures were identified, and their tortuousities were determined. The effluent samples were analyzed for pH, calcium concentration, and unconsumed acid concentration.
Coreflood studies indicated that 5:5 wt% HCl:MSA blend was the most suitable candidate for matrix acidizing among the three blends tested (2.5:7.5 and 7.5:2.5 wt% HCl:MSA being the other two blends investigated). At the optimum injection rate of 7.5 cm3/min, both 2.5:7.5 and 5:5 wt% HCl:MSA mixture required lesser pore volumes (PVs) of acid to reach breakthrough, compared to their individual acid controls. A single, straight, and dominant wormhole was observed with no branching and less tortuousity in both the cases. The control experiments with equivalent concentrations of HCl and MSA required higher PVs of acid to reach breakthrough with branching during wormhole propagation. Calcium ion dissolution was least for the 5:5 wt% mixture among the three blends tested. Higher unconsumed acid concentration was noted in case of 5:5 wt% compared to 2.5:7.5 wt% blend, thus promising greater penetration depth with the same PV of acid. On the other hand, the wormhole formed by the acid blend of 7.5:2.5 wt% HCl:MSA required almost the same PV of acid to reach breakthrough as its corresponding HCl control, and it was more enlarged and tortuous than its corresponding MSA control. 5:5 wt% HCl:MSA blend creates deeper wormholes and retards the HCl reaction with the rock matrix.
Major advantages rendered by the new acid mixture include: (1) deeper wormholes that will ultimately result in enhanced well productivity, and (2) cost effectiveness in carbonate stimulation compared to standard systems currently used in the market.
Method for Estimating and Analyzing for TOC of Hydraulic Fracturing Fluids
Authors: Harry David N. , Mallory Matt , Tucker Scott 
Published: March 2017

Abstract
Total Organic Carbon (TOC) is a characteristic of the amount of organic carbon present in a chemical compound or mixture, such as a hydrocarbon-bearing formation, water, or even a fracturing fluid. Organic carbon is a potential measure of food available for bacteria, and, as such, an indirect measure for the potential for wellbore fouling, formation damage, and regained permeability. For this reason, TOC is often used as an indicator of overall water quality across multiple industries, and is becoming more prevalent as a general indicator of water quality for frac reuse. TOC has been demonstrated to be directly correlative to the much-more difficult and time-dependent determination of Biochemical Oxygen Demand (BOD), and a recently developed method by which TOC can be analyzed in the field has made TOC determinations even more accessible.
The paper provides a theoretical determination of the TOC of over 100 fracturing fluid additives and compares the results with a field method for making TOC determinations. Also provided are examples on how to use TOC values for individual stimulation fluid additives to estimate the TOC of the entire frac fluid as pumped. The result of the exercise in assessing the TOC content of various slickwater and crosslinked polymer fluids provides a comparative guide for potential downhole bacterial and formation damage issues.
It is therefore possible to estimate the potential for proppant pack and/or formation damage with knowledge of the TOC of a fracturing fluid prior to its selection without having to resort to an analysis of the fluid. Also provided are insight into the range of TOC's that might be observed in various spent frac flowback waters as they are associated with general frac fluid types, such as Slickwater or Crosslinked frac fluids. Armed with knowledge of the TOC of actual flowback it may be possible to determine whether or not additional well cleanout operations might improve well productivity.
Inhibition of Calcium Carbonate Scale in the Presence of EOR Chemicals
Authors: Wang Qiwei , Al-Nasser Waleed , Al-Dawood Faez , Al-Shafai Tawfiq , Al-Badairy Hameed , Shen Shouwen , Al-Ajwad Hassan , Liang Feng 
Published: March 2017

Abstract
A field trial has been planned for a chemically enhanced oil recovery (EOR) project in Saudi Arabia. The injection chemicals will be a combination of surfactants and polymers. There is a concern that the breakthrough of these chemicals in produced water could affect scale formation process and interfere with the scale treatment program. The objective of this study is to investigate the potential impacts of the injected EOR chemicals on calcium carbonate (CaCO3) scale inhibitor performance.
Laboratory tests were carried out using static bottle and dynamic tube blocking methods. CaCO3 scale inhibition was studied in the absence and presence of the EOR chemicals at the estimated peak breakthrough concentrations, i.e., 200 mg/L polymers and 150 mg/L surfactants. Three different types of inhibitors were evaluated: tri-phosphonate, penta-phosphonate, and polyacrylate. Inhibition (%) from the bottle test and minimum effective dose (MED) based on the tube blocking method were determined for each inhibitor at 160 °F. Scale precipitates from the bottle tests were also characterized for morphology and polymorphs using environmental scanning electron and X-ray diffraction (XRD) techniques.
Obtained results showed significant reductions in scale inhibitor performance by the EOR chemicals. In dynamic tube blocking tests, the MED vaules of inhibitors were increased roughly 10 times with the EOR chemicals. The static bottle tests showed considerable changes under the test conditions. For example, the inhibition (%) of the penta-phosphonate based inhibitor at 20 mg/L was diminished from 100% to 20%; and the inhibition (%) of the tri-phosphonate inhibitor was decreased from 100% to below 50% and 70%, respectively, at 10 mg/L and 20 mg/L. The polymeric inhibitor completely lost its inhibition efficiency over the tested concentration range of 2 mg/L to 20 mg/L. The impact of EOR chemicals were also demonstrated by the remarkable ranges of crystal morphologies, changing from simple aragonite columns to nanorod, distorted spheroid, and flower-like superstructure in the presence of EOR chemicals and inhibitors.
This paper presents the first reported comprehensive study on the impacts of the EOR chemicals on CaCO3 scale formation and prevention. Results suggest that the performance of scale inhibitors could be substantially affected by the EOR chemicals. Such potential impact should be determined and a new scale treatment program should be developed for the success of EOR projects.
Automatic Optimisation of Oilfield Scale Inhibitor Squeeze Treatments Delivered by DSV
Authors: Vazquez Oscar , Ross Gill , Jordan Myles , Baskoro Dionysius Angga , Mackay Eric , Johnson Clare , Strachan Alistair 
Published: March 2017

Abstract
Oilfield scale deposition is one of the important flow assurance challenges facing the oil industry. There are a number of methods to mitigate oilfield scale such as sulphate reduction of the injected brine, flow modification to reduce water flow, damage removal by dissolvers or physically by milling or reperforating, and finally, inhibition, particularly recommended if a severe risk of sulphate scale deposition is present. Inhibition consists of the injection of a chemical which prevents the deposition of scale, either by stopping nucleation or retarding crystal growth. The inhibiting chemicals are either injected in a dedicated continuous line, or bull-headed as a batch treatment into the formation, commonly known as a scale squeeze treatment. Generally, scale squeeze treatments consists of the following stages: preflush, to condition the formation or act as a buffer to displace tubing fluids; main treatment, where the main pill of chemical is injected; overflush, to displace the chemical deep into the reservoir; followed by a shut-in stage to allow further chemical retention; finally, the well is put back in production. The well will be protected as long as the concentration of chemical in the produced brine is above a certain threshold, commonly known as minimum inhibitor concentration (MIC), usually this value is between 1 and 20 ppm. The most important factor in a squeeze treatment design is the squeeze lifetime, which is determined by the volume of water or days of production where the chemical return concentration is above MIC.
The main purpose of this paper is to describe the automatic optimisation of squeeze treatment designs using an optimisation algorithm, in particular, using particle swarm optimisation (PSO). The algorithm provides the optimum design, which strictly speaking in terms of squeeze treatment designs, it provides the longest squeeze lifetime, although, it might not be the most efficient. To determine the most efficient design, an optimisation algorithm is used to provide an optimum design based on the following objectives: operational deployment costs, chemical cost, total injected water volume and squeeze treatment lifetime. Operational deployment costs include support vessel, pump and tank hire. There might not be a single design optimising all objectives, thus the problem becomes a multi-objective optimisation. The algorithm is capable of analysing a great number of designs, making it easy to identify the designs that are non-dominated, which provides the right amount of information to identify the most cost effective squeeze treatment design, and therefore cutting total treatment costs.
Benign Use of Inclusion Complex Formation Property of Cyclodextrin and Its Application in Cement Fluid-Loss Control
Authors: Remitha A K , Agashe Snehalata , Reddy B R 
Published: March 2017

Abstract
Synthetic polymers have long been used as fluid-loss additives (FLAs) in hydraulic cement slurries for cementing subterranean zones. Typically used synthetic polymeric materials include N,N-dimethylacrylamide and sulfonated acrylamide monomers, which are preferred for high temperature applications. However, as these materials are less environmentally acceptable, the search for more environmentally acceptable chemical increases. Although preferred materials are biopolymers, they sometimes impart high slurry viscosity at ambient temperature, and cause thinning and settling of the cement slurries at elevated temperatures. Thus, there is a need for an additive composition that is environmentally acceptable and performs better over a wide temperature range.
This paper presents a novel idea of using a combination of two biopolymers, a hydrophobically modified (HM) biopolymer and a hydroxypropyl derivative of cyclodextrin (DCY) for controlling fluid loss, while imparting better cement slurry properties, stability, and viscosity. HM biopolymer as an FLA by itself causes excessive surface slurry viscosification at ambient temperature. However, when DCY was added into the cement slurry, optimum slurry viscosities were observed at ambient temperature, thus avoiding pumping issues. Laboratory experiments showed that the fluid-loss control was excellent, but the viscosity of cement slurry was high at ambient temperature when the HM biopolymer was used as a FLA by itself. The addition of DCY reduced the surface viscosity without compromising fluid-loss control and without affecting other properties. Studies conducted at elevated temperatures revealed that the HM biopolymer was left intact to maintain the cement slurry viscosity at that temperature, thereby helping prevent settling issues. Also, no significant effect on compressive strength development and thickening time of the cement slurry was observed with the addition of DCY molecules. The results of laboratory experimentation at ambient and elevated temperatures support the formation of in-situ inclusion complex formation of DCY molecules with the HM biopolymer.
A New Theoretical Model for the Induction Time and Scale Inhibitor Dosage Predictions for Calcite and Barite Over Wide Ranges of Temperature, Inhibition Concentration and Saturation Index
Authors: Dai Zhaoyi , Zhang Fangfu , Yan Fei , Bhandari Narayan , Ruan Gedeng , Zhang Zhang , Liu Ya , Alsaiari Hamad A. , Lu Yi-Tsung , Deng Guannan , Kan Amy T. , Tomson Mason 
Published: March 2017

Abstract
Mineral scale formation can lead to the blockage and shutdown of production wells in the oil and gas industry. Large amounts of scale inhibitors are added to mitigate the losses due such mineral scale formation. Both insufficient and excessive scale inhibitor additions can cause unnecessary expenses. Because inhibition mechanisms are poorly understood, current models do not predict accurately the minimum effective dosage (MED) required for different inhibitors, temperatures, and inhibition times over wide ranges. Using a new approach, this paper developed a theoretical model to predict scale inhibition kinetics based on the classical nucleation theory and the regular solution theory. This model assumes that scale inhibitors can change the nucleus structure and the apparent saturation status of the scale minerals. These impacts were modeled to be proportional to the inhibitor concentrations. The model accurately predicted the precipitation and inhibition kinetics of barite and calcite with or without the presence of eight different scale inhibitors up to 90 and 175°C, respectively. This study can be used as a template to evaluate scale and inhibition kinetics, predict MED, and elucidate scale inhibition mechanisms on a common theoretical basis.