bluuebunny/crossref_metadata_2025_split huggingface dataset:
Selection and Application of Organic Clay Inhibitors for Completion Fluids
Authors: Gomez S. , Ke M. , Patel A. 
Published: April 2015

Abstract
Clay instability problems in the reservoir zones can create risks with costly consequences for completion operations. Some sandstone reservoir rocks contain significant amounts of interstitial clay within the pore system. Clays are also present in reservoirs with interbedding shale and sandstone. Swelling and dispersion of these clay minerals in the reservoir can affect wellbore integrity, induce formation damage, reduce gravel pack permeability, plug screens, and cause failures in the completion tools and assemblies.
In many situations completion brines can provide some degree of inhibition, some reservoirs require more effective and permanent treatments to control reactive clays. Numerous products are available for clay inhibition, but a majority of them were primarily developed for drilling fluids. Organic additives for clay inhibition used extensively in drilling fluids have been transferred into the completion brine technologies to provide effective solutions in reservoirs with a high potential for clay instability. Chemical compatibility is a critical factor in the selection of additives for completion brine.
This paper will present the results of a study conducted with monovalent and divalent brines treated with different types of organic clay inhibitors. Compatibility tests will show the cases where inhibitor additives are compatible with multiple types of brines. Other cases present strong chemical incompatibilities between specific brines and specific organic inhibitors. Discussion of the chemistry of organic clay inhibitors and their chemical interactions with brines will be presented. Discussion of the chemical interaction causing incompatibilities will be presented and associated with the effects of brine properties (pH, density, and composition). Furthermore, different rock-fluid interaction tests using actual reservoir formation samples are presented to show the performance of some of the most common organic clay inhibitors in completion brines. The data presented can be used as a guideline to select compatible clay inhibitors according to the brine properties.
A New Chemical Enhanced Oil Recovery Method?
Authors: Hosseini-Nasab S.M. , Zitha P.L.J. , Mirhaj S.A. , Simjoo M. 
Published: April 2015

Abstract
Alkali-Surfactant-Polymer (ASP) is one of the most attractive chemical EOR methods. In properly designed ASP formulations, the alkali-surfactant provides ultralow interfacial tension (IFT) between drive aqueous fluid and the displaced oil whereas polymer ensures a good mobility control. Nevertheless, the efficiency of ASP can be much less than expected under various reservoir conditions including low permeability, high temperature, high formation brine salinity, presence of divalent cations (Ca+2, Mg+2) in the formation brine. This is due to polymer degradation or precipitation, low injectivity, scaling in well and surface equipment. This paper reports an experimental study of new a chemical EOR which has the potentially to overcome above drawbacks. The chemical formulation consists of the combination of no-polymeric viscosity enhancement compound and a blend of two surfactants. The performance of this chemical formulation was evaluated by a series of core-flood tests on Bentheimer sandstone cores, under stable gravity conditions, with the aid of X-ray Computed Tomography. A significant reduction of the residual oil saturation was observed by constructing the capillary desaturation curves (CDC) suggesting that proposed formulation is potentially a rather good chemical EOR agent.
Core-Shell Systems for Delayed Delivery of Concentrated Mineral Acid
Authors: Johnson Leah M. , Shepherd Sarah D. , Rothrock Ginger D. , Cairns Amy J. , Al-Muntasheri Ghaithan A. 
Published: April 2015

Abstract
Acid stimulation, for both oil and gas wells, greatly supports the industry as a versatile means of enhancing production. Although acids enhance carbonate reservoir permeability to hydrocarbons, the reactions rates of the acid (e.g., HCl) with the rock often occur too rapidly at high temperatures, leading to a reduction in acid penetration. Several methods exist to improve the effectiveness of acidizing in high temperature reservoirs (i.e., greater than 250°F), including the use of emulsified acid, mixtures of hydrochloric acid (HCl) and organic acids, and gelled acids. Many of the aforementioned techniques are effective forms of treatment; however, they hold significant limitations such as reduction in acid efficiency, poor control over penetration depth and the requirement of corrosion inhibitors. Acc ordingly, encapsulated HCl holds potential as an attractive alternative to address these shortcomings since its prolonged release profile would permit transport of acid deep within the reservoir. In addition, when successfully encapsulated, this technology could completely eliminate the use of corrosion inhibitors. Herein, we demonstrate the design and preparation of highly modular core-shell particles comprising concentrated HCl encapsulated within an acrylate-based thermoset polymer shell. We show that the shell generation mechanism (i.e., photopolymerization of acrylate monomers) is compatible with concentrated HCl and further detail the encapsulation process. Our results demonstrate that acid release profiles are dictated by the properties of the shell material, enabling a prolonged delivery of HCl in laboratory studies. This is a first step towards the design of particle shell systems that can tolerate the harsh reservoir conditions, including high temperatures, pressures, and salinity of mixing water. A tunable core-shell delivery system that encompasses a sufficient amount of strong mineral acid is well-poised to address the unmet need of deeper penetration of HCl into the reservoir enabling greater stimulation efficiency.
Formulation of Surfactants for Very Low/High Salinity Surfactant Flooding without Alkali
Authors: Zhang Guoyin , Yu Jianjia , Du Cheng , Lee Robert 
Published: April 2015

Abstract
To address the disadvangates associated with the use of alkali during surfactant flooding, such as reduction of polymer viscosity, formation scaling, corrosion hazards, and emulsion formed by the produced fluids, this study focuses on the formulation of surfactants without alkali for either very low salinity (&lt;10,000 ppm TDS) or very high salinity (&gt;100,000 ppm TDS) surfactant flooding. A series of laboratory tests were conducted to investigate the synergism among anionic, cationic, nonionic and zwitterionic surfactants for EOR purposes based on IFT and phase behavior measurements. All the surfactants used in this study are commercially available and no alkali is added for all cases. The results demonstrate that strong interactions between anionic/cationic and anionic/zwitterionic surfactants make them form highly active aggregates which behave more like nonionic surfactants and exhibit great salt tolerance capability. Ultra-low interfacial tensions (IFTs) with the order of magnitude of 10−3 mN/m are achieved by these mixtures. By adjusting the mixing ratio, they can be tailored easily to reservoirs with different salinities and solid surface charges. The anionic/zwitterionic surfactant mixtures at certain pH show exceptional performance, which are able to form middle microemulsion phase from as low as 0 till up to 180,000 ppm TDS salinity. The study also shows the addition of cosolvents (short chain alcohols) should be thoroughly justified during surfactant formulation because they can improve the surfactant solubility and speed phase coalescence. However, they may adversely afftect the water and oil solubilization capacity.
Application of Advanced Mass Spectroscopy Techniques for Improved Scale Management in Conventional and Sub-Sea Fields
Authors: Heath Steve , Johnston Clare , Gundersen Thomas , Bjellaas Thomas 
Published: April 2015

Abstract
An essential part of any scale squeeze management strategy for any oilfield is the capability to accurately and precisely determine the residual scale inhibitor concentration in the produced fluids. This data in combination with ion analysis, suspended solids and productivity index is essential to determine the lifetime efficiency of scale squeeze treatments.
In recent years the stricter environmental regulations in the North Sea, coupled with the development and operation of more complex fields in harsh scaling environments, has led to increased use of environmentally friendly polymeric scale inhibitors. The accurate and specific analysis of polymeric scale squeeze inhibitors is known to be difficult and has led to the development of a toolbox of advanced scale inhibitor analysis techniques based upon liquid chromatography with mass spectrometric detection (LC-MS). These methods offer the potential to improve scale management capability in conventional and sub-sea fields through improved scale inhibitor detection at low levels.
In addition, mass spectrometric detection provides the ability to selectively detect chemical functional groups, contained within polymeric scale inhibitor molecular structures, which were previously not distinguishable. This is a distinct advantage for multiple scale inhibitor analysis capability in produced brines as certain chemical groups can now be used as tags without having to modify the chemistry of commercially available inhibitors.
The ability to detect polymeric scale inhibitors at very low MIC &lt;1ppm with improved confidence has the potential for significantly extending scale squeeze lifetimes. In addition, this has now allowed highly efficient polymers to be used in field situations where scale squeezing had either been stopped or the lifetime was significantly compromised because of the lack of confidence in the scale inhibitor return profiles and the interferences from background reservoir Phosphorus or topside scale inhibitors.
Specific examples from North Sea fields, including both sub-sea and platform wells, will be presented where the scale management has been significantly improved through the application of the advanced LC-MS techniques. In addition, the use of the LC-MS techniques targeting specific chemical groups as molecular tags to enable multiple scale inhibitor detection for a range of quaternary amine acrylic co-polymers will be presented.
Viscoelastic Behavior and Proppant Transport Properties of a New High-Temperature Viscoelastic Surfactant-Based Fracturing Fluid
Authors: Gomaa A.M. , Gupta D.V.S. , Carman P. 
Published: April 2015

Abstract
Viscoelastic surfactant (VES) fracture fluids were developed as a nondamaging alternative to conventional polymer-based fluids. However, the viscosity performance of typical VES fluids is dramatically reduced at high temperature. Therefore, these fluids are typically limited to treat relatively low-temperature formations unless foamed with nitrogen or carbon dioxide. Recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. Thus, combination of rotational and oscillatory measurements to determine the fluid viscous and elastic properties can better predict whether the fluid can be applied successfully in the field.
The present study was conducted to introduce a new Gemini VES system that can gel and maintain useful viscosity up to 275°F, which can provide additional downhole benefits. Dynamic and static proppant settling tests were conducted using a high-pressure/high-temperature visualization cell to confirm the effect of elastic properties of this fluid on proppant settling. Finally, proppant settling tests were conducted with three proppant types of the same size, but different density and shape at a range of concentrations.
Experimental results show that the surfactant gel behaved as an elastic material (elastic regime), where the elastic modulus (G') was dominant over the viscous modulus (G”) during the tested range of frequency. This behavior gives perfect proppant transport properties. At temperature less than 225°F, Values of G′ were independent of the frequency and/or shear rate values, while G” increased with increasing frequency and/or shear rate. At higher temperature, both G′ and G” increased with increasing frequency and/or shear rate. This gives a good proppant-carrying capacity during dynamic conditions (mixing and injection) with a small pressure drop. The addition of an internal liquid breaker increases the viscous regime with time and temperature. When elastic regime dominates, 100% proppant suspension was confirmed for at least two hours at static and dynamic conditions and temperatures in the range of 75 to 250°F.
Environmentally-Conscious Biocides for Long-Term Protection of the Fracture
Authors: N'Guessan Stephen , Raymond Jon , Navarrete Reinaldo 
Published: April 2015

Abstract
Combining a biocide's effectiveness to reduce bacterial growth as well as ensuring its compatibility with fracturing fluids is a common challenge faced in oilfield applications. This paper describes a series of biocides and combinations of biocides with an improved environmental profile, which protect the formation and proppant pack for extended periods of time. Different biocides were selected based on their environmental and toxicological profile, and their ability to reduce bacterial growth for up to 7 weeks. Two types of biocides were evaluated: (1) rapid-kill biocides under conditions mimicking surface conditions and (2) preservative biocides under conditions mimicking long-term reservoir conditions. Combinations of both biocide types were also evaluated. Two types of fracturing fluids were used including a fully formulated slickwater system and a fully formulated linear guar gel. The fracturing fluids containing the biocides were heat-aged for 50 days at 167°F. Periodically, samples were extracted and challenged with stock cultures of SRB and APB for bacterial kill studies.
The results demonstrated that preservative biocide chemistries can be effective in the protection of the fracture for extended periods of time. Also, optimum combinations of rapid kill biocides and long term preservatives were observed that can be effective in the short and long term. In some cases, enhanced antimicrobial effects were observed between the two biocide types that augmented the long term effect of the preservatives. The results of this study demonstrate a systematic process for optimization of biocide treatments capable of protecting the formation and fracture long after the fracturing process has ceased. The benefit for the well is compounded in that polysaccharide gelling agents and high molecular weight friction reduction agents, present in many fracturing fluid formulations, act as food for bacteria in the fracture. If prolonged bacterial growth is not controlled in the fracture following treatment, then the long term viability of the well is put at risk.
Low Salinity Chase Waterfloods Improve Performance of Cr(III)-Acetate HPAM Gel in Fractured Cores
Authors: Brattekås Bergit , Graue Arne , Seright Randall S. 
Published: April 2015

Abstract
Polymer gels are frequently applied for conformance improvement in fractured reservoirs, where fluid channeling through fractures limits the success of waterflooding. Placement of polymer gel in fractures reduces fracture conductivity, thus increasing pressure gradients across matrix blocks during chase floods. A gel-filled fracture is re-opened to fluid flow if the injection pressure during chase floods exceeds the gel rupture pressure, thus channeling through the fractures resumes. The success of a polymer gel treatment therefore depends on the rupture pressure.
Swelling of gels, e.g. pre-formed particle gels, due to salinity differences between the gel network and surrounding water phase has recently been observed, but the effect has been less studied in conjunction with conventional polymer gels. Using core floods, this study demonstrates that low-salinity water can swell conventional Cr(III)-acetate HPAM gels, thereby improving gel blocking performance after gel rupture.
Formed polymer gel was placed in fractured core plugs and chase waterfloods were performed, using four different brine compositions of which three were low-salinity brines. The fluid flow rates through the matrix and differential pressures across the matrix and fracture were measured and shown to increase with decreasing salinity in the injected water phase. In some cores, the fractures were re-blocked during low-salinity waterfloods, and gel blocking capacity was increased above the initial level. Low-salinity water subsequently flooded the matrix during chase floods, which provided additional benefits to the waterflood. The improved blocking capacity of the gel was caused by a difference in salinity between the gel and injected water phase, which induced gel swelling. The results were reproducible through several experiments, and stable for long periods of time in both sandstone and carbonate outcrop core materials. Combining polymer gel placement in fractures with low-salinity chase floods is a promising approach in integrated EOR (IEOR).
A Novel Approach to Crosslink Delay of Low-pH Fracturing Fluid
Authors: Legemah Magnus , Sun Hong , Carman Paul , Mayor John 
Published: April 2015

Abstract
Carboxylated guar or cellulose fluids are among the most robust fracturing fluids because they crosslink at both high and low pH with transition metal compounds and exhibit tremendous thermal stability. Low-pH fluids are preferred for stimulation treatments using low-quality water or when foamed with CO2 for low-pressure formations. Such systems are often challenged with rapid viscosity development or insufficiently delayed crosslinking, which generates high pipe friction pressure. The ability to effectively control viscosity development in low-pH fracturing fluid will improve the applicability of carboxylated guar- or cellulose-based fracturing fluids.
A novel approach is reported in this paper to delay the crosslink of low-pH fracturing fluid using a slow-dissolving, solid organic acid in hydrated polymer containing zirconium crosslinker, to slowly lower the pH of the fluid to the optimum pH where crosslinking occurs. The slow pH reduction results in a slow viscosity build-up (delay) with increasing temperature, without compromising fluid rheology performance. The novel approach will complement existing chemical delay methods. Preliminary results show that crosslink time can be increased by using less organic acid; for instance, decreasing organic loading from 16 to 4 ppt led to crosslink time increase of 97 to 510 s.
To further simplify field handling of such organic acid material, the organic acid is slurried in hydrocarbon. Dissolution experiments demonstrate that the slurried acid (1.024-1.710 g/100 mL) dissolves in water more slowly than an approximate amount of solid acid (0.43g/100mL), which offers additional benefits to control delayed crosslinking.
This new patent-pending approach to crosslink delay increases the delay options for crosslinked low-pH carboxylated guar and cellulose because the delay can be tailored to suit different well stimulation fluid requirements. The rheology evaluation as a function of varying loading of both solid and slurried organic acid, as well as the rate of pH change are discussed in this paper.
Computational Modeling of Temporary Clay Stabilizers Supported by Performance Testing
Authors: Aften Carl W. , Ma Qisheng 
Published: April 2015

Abstract
The performance of systematically substituted temporary clay stabilizers has significant correlation with performances predicted by computational modeling. The model binding energies of different clay stabilizers onto various bentonite crystalline faces were independently calculated and corresponded well with a standard bench-top performance method indicating a systematic approach in the development of temporary clay stabilization performance may be realized.
Various clay stabilizers are employed when stimulation requiring aqueous based fluids is necessary in water sensitive formations. Typically, if swelling or migrating clays are present, temporary or permanent stabilizers are utilized. Low molecular weight temporary stabilizers as a rule perform above a critical level concentration, but as the stabilizers concentration diminishes in the fracturing fluid due to flowback, formation fluid displacement, or other mechanisms, the clay can swell reducing porosity and permeability. Permanent stabilizers are generally higher molecular weight and can adhere to single or multiple clay platelets thus dissolution of the stabilizer into the fluid is not favored and the beneficial anti-swell effect is of higher duration. It was discovered when using binding energies of substituted ammonium ions on a bentonite interlayer, the binding energies correlated well with performance testing.
The binding energy of ammonium ions substituted with 0 to 4 methyl groups or choline were calculated on the 001 crystal face(s) of bentonite. Bentonite being a 2:1 swelling clay had its inter-crystalline space gapped at 8 to 20Å. Unique molecular ions were introduced to this space and the binding energies were calculated using a Monte Carlo Isothermal Adsorption method. Performance testing was then conducted using a low pressure Bariod fluid loss cell. A set concentration of sodium bentonite was blended into water a specific RPM and duration in the presence of the particular ammonium ion, placed in the cell and pressure was applied and leak off rate were measured. The resulting leak off rates were compared to the binding energy.
The design of efficient temporary clay stabilizers can be directly linked to performance. Further, the duration of the stabilization may also be modeled in a way where experimentation would be difficult in flow through porous media.
Development And Evaluation Of A Novel, Rapid And Highly Efficient H2S Scavenger To Meet The Challenges Of Presalt Offshore Applications In Brazil
Authors: Taylor G. N. , Magalhães A. A. , Bustamante F. Carreira , Bonfim A. L. 
Published: April 2015

Abstract
The “Pre-salt application” offers some unique and challenging difficulties for producers and the service companies who support their operations. The carbonate reservoirs which occur in Brazilian deepwater fields provide unique challenges that relate to high temperatures, the high H2S content, as well as severe saline and scaling conditions. It is quite common to find oil and gas fields with estimated H2S level in the produced gas between 100 and 200 ppmv and salinity approximately 230,000 mg/L. Hydrogen sulfide is a poisonous gas, very harmful to life, and removal is essential to comply with sulfur emissions, as well as to ensure system and pipeline integrity.