bluuebunny/crossref_metadata_2025 huggingface dataset:
Investigation of Microorganisms in a West Texas Oilfield Using Growth and Genetic Testing
Authors: Kilbane John , Wylde Jonathan , Williamson Andy
Published: April 2015

Increasing corrosion issues at a sour west Texas oilfield in the Permian Basin suggested that microbiologically influenced corrosion (MIC) could be the cause. However, multiple water and biofilm samples failed to show significant concentrations of microorganisms using traditional microbial growth media for the cultivation of APB, GHB and SRB. Microbial growth tests indicated the highest concentration of microorganisms as 103 cells/ml, while the results of genetic testing using qPCR indicated that microbial concentrations of up to 1000-fold higher were actually present. It was speculated that the type of microorganisms present in the samples from this saline (6 to 10%) thermophilic (60°C) field may not grow well in the standard microbial growth media. Additionally, isotopic analysis of sulfur in the hydrogen sulfide gas and in sulfate from formation water are consistent with microbiological sulfate reduction being responsible for reservoir souring at this location.

To characterize the microbial community composition of these samples more thorough DNA sequencing was performed on selected samples. The results of DNA sequence analyses show that the percentage of unclassified DNA sequences (unidentifiable at the genus level because no similar DNA sequences are present in the global database) ranged from 1.8% to 25.8%. Of the bacteria that could be identified, a high percentage of halophilic (salt loving) bacteria, and of SRB were observed in all samples.

These results demonstrate that genetic testing can provide data about microorganisms in some oilfield samples, even when standard microbial growth tests fail to indicate the presence of microorganisms. Moreover, standard microbial growth recipes are not well suited for the growth of microbes from all locations and there is a need for new formulations of microbial growth media for use in some locations, such as the Permian Basin. Using standard microbial growth tests in this case would have seriously under-estimated the integrity risk caused by the presence of high numbers of SRB that were demonstrated to be present by genetic analyses. Armed with the knowledge that significant concentrations of microbes were indeed present, but had different nutritional requirements than those provided in standard microbial growth media, new formulations of microbial growth media were developed by Intertek that are tailored to the requirements of these Permian Basin samples.
Investigation on a Novel Polymer with Surface Activity for Polymer Enhanced CO2 Foam Flooding
Authors: Xu X. , Saeedi A. , Rezaee R. , Liu K.
Published: April 2015

CO2 foam flooding has been widely researched due to its outstanding capacity to mitigate viscous fingering, gravity override and unfavourable injectivity profile, which enables CO2 flooding to be more applicable and economical. Yet the primary concern of CO2 foam flooding is the instability or rupture of bubbles under harsh reservoir condition, thus a great number of investigations have been conducted to address this issue.

Through adding polymer into surfactant solution, Polymer Enhanced Foam (PEF) technique could stabilize foams due to dramatical increase in apparent viscosity. However, hydrolysed polyacrylamide (HPAM), the most used polymer, will greatly reduce the foamability of surfactant solution, which means sufficient foam may not be generated and sweep efficiency remains poor. What's more, HPAM is sensitive to salinity and temperature, affecting its behaviour in reservoirs. This research aims to study the performance of PEF using AOS as the foaming agent which is enhanced by polymer (HPAM/a novel polymer with surface activity, named AVS). One on hand, because of the surface active group on the molecular chain, this polymer can thicken surfactant solution without greatly affecting its foamability; on the other hand, phenyl group, sulfo group and other functional groups are introduced into polymer molecule, making AVS more salt and temperature tolerance.

The results demonstrated: 1) Under harsh condition (high salinity and temperature), viscosities of AVS solution were higher than that of HPAM; 2) The surface tensions between AVS solution and CO2 were lower, which was attributed to the introduction of surface activity group;3) The foaming factors of AOS/AVS were remarkable in a wide range of brine salinity (1000-50000 ppm) and temperature (25 °C-60 °C); 4) At high pressure (2000psi), the blockage of CO2 foam enhanced by AVS was encouraging and satisfactory; 5) During core flooding, if under same test conditions, tertiary oil recoveries obtained by AVS/AOS were 5% -7% higher than that of HPAM/AOS.

It is believed that this novel polymer has great potential in application of polymer enhanced CO2 foam flooding under various reservoir conditions.
Development and Evaluation of Non-Ionic Polymeric Surfactants as Asphaltene Inhibitors
Authors: Wang Min , Kaufman Jonathan , Chen Xin , Sungail Craig
Published: April 2015

Asphaltenes are of particular interest to the petroleum industry because of their depositional effect which creates problems for production, storage, transportation and refinery processes. A class of non-ionic polymeric surfactants has been developed to prevent the aggregation of asphaltene colloids in crude oils. A surfactant dosage rate as low as 25 ppm can be used to keep the asphaltenes dispersed at nearly 100 %. These polymeric surfactants are made from sustainable and biodegradable raw materials and free of BTEX, other aromatic solvents and phenol formaldehyde resin.

The polymeric surfactants were synthesized with a range of monomers at various ratios and under different conditions. The products were then tested in three crude oils from the USA and Canada (API: 45-11 °) to evaluate their performance in a range of systems. The inhibition effect was analyzed with an optical scanning device according to ASTM D7061-06. It was found that the chemical bonding and physical absorption between an asphaltene molecule and the polymeric surfactant played an important role in stabilizing the asphaltene colloids in crude oil. The hydrophobic chain of the polymeric surfactant provided steric hindrance between the asphaltene colloids while the polar groups gave multiple interaction points for bonding and absorption to the asphaltene. Achieving a balance between these aspects of the molecular design has created a new class of polymeric surfactants based on sustainable and biodegradable raw materials which efficiently inhibit the precipitation of asphaltenes from a range of crude oils at low dose rates.
Development of Novel Anti-agglomerant Chemistries with Reduced Localized Corrosion Potential to Stainless and Duplex Steels
Authors: Panchalingam Vaithilingam , Liu Zhengwei , Rivers Gordon , Garza Tim , Cook Stuart , Stead Paul , McEachern Heather , Frostman Lynn
Published: April 2015

Low dosage hydrate inhibitors (LDHIs) have been used as alternatives to thermodynamic inhibitors such as methanol or mono ethylene glycol (MEG) to control hydrate problems. The major advantage of using LDHIs is that they control with a much lower dosage, typically 1 to 3vol% (based on water production volume), thus lowering storage requirements and logistical challenges, compared to much higher volumes required for methanol or MEG. Anti-agglomerants (AAs), as one type of LDHI, allow hydrates to form but inhibit growth and agglomeration of hydrate crystals. Some very effective AAs exhibit a pitting corrosion risk for offshore umbilical chemical delivery systems under certain conditions. An electrochemical method of cyclic potentiodynamic polarization (CPP), a modified ASTM G-61 method at ambient temperature, and immersion testing using a modified ASTM G-31 method at elevated temperatures were used to evaluate pitting tendencies of AA formulations containing corrosion inhibitors on stainless and duplex steels. Initially, these corrosion inhibitors were effective in controlling pitting corrosion in stainless steel only as shown by CPP and immersion testing. After modifying the manufacturing process and adjusting solvent systems, the selected corrosion inhibitors have been shown to be effective for both stainless and duplex steels. Hydrate performance testing showed no performance compromise with the presence of corrosion inhibitors within the AA formulation or from changing the solvent system. Mitigation of pitting tendency was also confirmed by immersion testing at elevated temperatures.
Development of Novel Phosphate Based Inhibitors Effective For Oxygen Corrosion
Authors: Yepez Omar , Obeyesekere Nihal , Wylde Jonathan
Published: April 2015

Corrosion inhibitors can behave as cathodic inhibitors when they mainly suppress the cathodic reaction. Conversely, they can also be anodic inhibitors when they mainly suppress the anodic reaction. When corrosion inhibitors interact with both cathodic and anodic reactions, they may behave as mixed inhibitors. This paper documents the electrochemical characterization of a phosphate ester based inhibitor which created protection from oxygen corrosion. Potentiodynamic polarization was used to determine the inhibitor behavior during the anodic and cathodic processes of corrosion. A system comprising a carbon steel electrode in 3.5% NaCl and a gas phase composed of 3% O2 in 97% CO2 with and without an inhibitor has been defined and tested. The oxygen corrosion mechanism on carbon steel was established through the comparison of the cathodic and anodic currents in the presence of 3% O2 in 97% CO2 and 100% CO2. The probable mechanism of inhibition by imidazoline and phosphate esters as well as the role of a sulfiding agent was explored. In the presence of oxygen, the anodic more than the cathodic inhibition performance was more related to the overall corrosion inhibition. As expected, phosphate ester based inhibitors demonstrated to be superior to imidazoline base inhibitors to abate oxygen corrosion. These results were confirmed with open-circuit (autoclave) corrosion experiments.
Use Of Anti-Agglomerates for Sour Gases, High Water Cuts And Its Performance Evaluation
Authors: Treybig D.S. , Fowles R. , Stannard D. , Smith C.S.
Published: April 2015

Gas hydrates can be easily formed during the transportation of oil and gas in pipelines under certain conditions. Water content, low temperatures and elevated pressure are required for the formation of gas hydrates. The industry uses a number of methods to prevent blockage by hydrates such as thermodynamic inhibitors, kinetic inhibitors and anti-agglomerates. Large volumes of thermodynamic inhibitors are required for prevention of hydrate formation which may result in environmental concerns. Natural gas in the U.S. may contain as much as 15 to 25% of hydrogen sulfide, while the figure could be as high as 30 percent in the rest of the world. Some kinetic hydrate inhibitors available today may not be effective in gas streams with hydrogen sulfide.

The objective of this work was to develop a hydrate inhibitor for sour environments at high water cut. This paper also investigated the effect of different operating parameters such as concentration of the inhibitor, percent water cuts (25, 75 and 100), salinity (10,000 and 50,000 chloride brine) and gases (hydrogen sulfide, nitrogen, butane, carbon dioxide, propane ethane and methane). These anti-agglomerates were compared with kinetic inhibitors. Hydrate inhibitor testing was performed using an autoclave at 4 °C. Pressure, temperature and torque were recorded.

In this paper, we presented the development and use of a family of anti-agglomerate compounds that effectively function in a sour environment at high water cut. Torque measurements were used to determine the effectiveness of inhibitors. It was found in some cases that the torque for treatment containing ≤ 3% of these anti-agglomerates in 1% H2S was low (< 3 Ncm) compared to a control (> 20 Ncm) indicating no deposition of hydrates. Increasing the percentage of H2S to 4 % did not diminish the performance of selected anti-agglomerates. The best performing anti-agglomerate was also effective in both 10,000 ppm and 50,000 ppm chloride ions brine. These hydrate inhibitors maintained their effectiveness even with > 24 hour shut-in. Field studies on the application of selected anti-agglomerate was presented.
Delayed-Release Suspending Aid Provides Cement-Slurry Stability in High-Temperature, Horizontal Wells
Authors: Funkhouser Gary P. , Leotaud Lennox , Bratcher Jason
Published: April 2015

Successful liner cementing in unconventional shale wells is strongly dependent on slurry stability. A delayed-release, high-temperature suspending agent was developed that provides viscosification and stabilization of the slurry without causing excessive viscosification and mixing problems at the wellsite. The suspending aid was prepared from water-soluble, thermally stable monomers copolymerized with degradable crosslinking monomers. The crosslinks degrade as the temperature of the slurry increases, ultimately resulting in dissolution of the polymer and concomitant slurry viscosification. The performance of the suspending aid was demonstrated by means of laboratory testing under typical Eagle Ford shale conditions. Improvements were observed in terms of fluid-loss control (54 cc/30 min [control] to 28 cc/30 min), free fluid (5% [control] to 0%), sedimentation (Δρ 5.2 lbm/gal [control] to Δρ 0.2 lbm/gal), and consistometer off/on tests. Three field examples from the Eagle Ford are presented where the suspending aid was used to establish the desired mud-spacer-cement rheological hierarchy at bottomhole circulating temperature (BHCT); provide sufficient slurry stability to set the liner top plug, circulate out excess cement, and produce a competent cement sheath; and improve the mixability and stability of a barite-weighted spacer.
Microemulsions as Flowback Aids for Enhanced Oil and Gas Recovery after Fracturing, Myth or Reality: A Turnkey Study to Determine the Features and Benefits
Authors: Mahmoudkhani Amir , O'Neil Bill , Wylde Jonathan J. , Kakadjian Sarkis , Bauer Martin
Published: April 2015

Flowback aids have been long reported in the literature as being beneficial to enhance clean-up after stimulation treatments, and in particular hydraulic fracturing. The goal is for the flowback aids to allow the piston like flowback and return of fluids from the reservoir resulting in minimal losses to the formation and no memory effect that hampers back production. Microemulsions have also been reported in the literature and a review (including patent landscape) creates somewhat of a myth around their exact mechanism of performance and benefit to the application.

The present work was concerned with the development of flowback aids based on micro-/nano-emulsion technology for enhanced gas and oil recovery after fracturing application. The goal was to formulate microemulsion concentrates which form nanoemulsions when diluted into fracturing fluids and provide strong surface and interfacial tension reduction to minimize reservoir damage.

Microemulsions have been formulated with various possible surfactants and oil systems. The performance of the different formulations has been evaluated with different test methods, adopted from literature and industry best practice in order to screen for most promising microemulsion systems and compared to their aqueous equivalents to determine the performance benefits offered by emulsified packages. High throughput experimentation and robotic formulation was utilized to screen several thousand formulations from nearly 50 different surfactant packages. This allowed for incredible synergistic properties to be discovered very quickly and efficiently. The development of a new class of microemulsion package that is made up of almost 100% renewable and environmentally friendly components has made a large step change towards the state of the art of this class of flowback aids.

Regain permeability and core flow testing was performed on the best performing microemulsion formulations to determine the effect of field application. The result of this work was that microemulsions do offer some benefits over individual surfactants, not so much in surface tension modification but very much on the non-emulsification of crude oil and water and multiphase flow in porous media – so often seen as the primary damage mechanism in oil well fracturing.
Selection and Application of Organic Clay Inhibitors for Completion Fluids
Authors: Gomez S. , Ke M. , Patel A.
Published: April 2015

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

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

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

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 (<10,000 ppm TDS) or very high salinity (>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

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 <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

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

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

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

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

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

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.
Solubility Characterization of Asphaltene Deposits
Authors: Rogel E. , Ovalles C. , Moir M. , Vien J. , Morazan H.
Published: April 2015

In view of the great impact of asphaltene deposition in the petroleum industry, it is of paramount importance to estimate the tendency of crude oils and petroleum products towards precipitation as well as the potential amount of material that can precipitate. These are important parameters to consider in designing and monitoring of different processes in the petroleum value chain. It is common knowledge that asphaltene precipitation is strongly related to the colloidal nature of petroleum materials. Rather recently, a new method to evaluate the colloidal stability of crude oils was developed based on the determination of the solubility distribution of asphaltenes. It was found that samples from different origins give different solubility distribution patterns and that those patterns can be correlated to precipitation tendencies of crude oils.

In this work, asphaltene distributions in solid deposits are analyzed and compared to the original asphaltene distributions in the corresponding original oils. Additional chemical and physical properties were also examined and compared. This study aims to link specific asphaltene solubility distribution patterns to the formation of deposits and to find out how asphaltenes found in deposits are compared with the asphaltenes in the materials that originated them. This information is relevant for thermodynamic as well as kinetic modeling of the asphaltene deposition phenomena.

The results indicated significant differences between asphaltenes from the original crude oils and their corresponding deposits. Quantification of these differences in terms of solubility was carried out and showed that asphaltenes from deposits are in average composed of less soluble asphaltenes than those present in the original crude oils. In practical terms, this means that asphaltenes separated using heptane or pentane might not be representative of the asphaltenes found in deposits. The compositional variation of solid deposits seems to point out towards a complex mechanism of formation that is usually not considered in the tools used to model this phenomenon.
A Field Case Study of Inter-well Chemical Tracer Test
Authors: Sanni Modiu L. , Al-Abbad Mohammed A. , Kokal Sunil L. , Hartvig Sven , Olaf Huseby , Jevanord Kjersti
Published: April 2015

Tracers are increasingly being used as effective reservoir monitoring and surveillance (M&S) tool in the oil and gas industry. They can qualitatively or quantitatively gauge how fluid flows through the reservoir. Tracer surveys, conducted either as interwell tests or single-well tests, are one of the enabling technologies that can be deployed to investigate reservoir flow performance, reservoir connectivity, residual oil saturation and reservoir properties that control displacement processes, particularly in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations.

An inter-well chemical tracer test (IWCTT) was designed and implemented in a carbonate field with a diffuse fracture network on peripheral water-flood to determine reservoir connectivity, water breakthrough times, and fluid saturations. The reservoir is heterogeneous with layers of high to low permeability limestone with porosity a range of 20-30%, and interspersed with patchy layers of dolomites and a very competent anhydrite seal. The IWCTT was conducted on a very mature part of the field near the peripheral water injectors to determine the effectiveness of infill injector wells. Four distinct tracers were injected into four individual injectors and the residuals were monitored in four “paired” producers.

This paper reviews the complete design and implementation of the test, operational issues, and the analyses and interpretation of the results. The breakthrough times of the tracers are reported and interwell connectivity between the paired and cross-paired injectors and producers are analyzed. Tracers were detected in three of the paired producers, albeit at different breakthrough times. One tracer was also detected in a cross-paired producer. The tracer results were modeled using the current reservoir simulation model with fairly good matches. The tracer data were then used to fine tune the current reservoir simulation model. The IWCTT has been very effective in analyzing well interconnectivity in the reservoir and has led to better reservoir description and an improved dynamic simulation model. Plans for further implementation of this important M&S tool will also be shared.
Development and Qualification of New Zinc and Lead Sulphide Scale Inhibitors for Application under Harsh Conditions
Authors: Baraka-Lokmane S. , Hurtevent C. , Tillement O. , Simpson C. , Graham G.M.
Published: April 2015

The paper will describe the challenges facing sulphide scale control in the challenging environment found in Totals Elgin and Franklin Fields. It will present the advances made in developing new thermally stable and compatible chemical inhibitors able to withstand the extreme conditions in these fields. The paper will then describe the test methodologies and experimental approach developed to examine the performance of various prototypes or candidate chemicals followed by more detailed testing on selected chemicals under the more challenging field representative conditions as well as application specific testing for both squeeze treatment and downhole continuous injection at temperatures of 196°C/282 °F.

In collaboration with University of Lyon Total has developed a range of new inhibitor types specifically designed to inhibit sulphide scales and remain stable under the harsh conditions of these fields. The chemicals have been qualified independently using recently developed test methodologies for lead and zinc sulphide and show better performance against these unconventional scales comparing to the other chemistries examined. In addition, a new method was developed for scale inhibitor residual analysis. This method based on time resolved fluoroscopy allows a quick and very sensitive measurement.

The work concludes that a new range of Zn/Pb sulphide specific chemicals have been developed for field application with selected species also being suitable for application under the extreme conditions of the Elgin and Franklin Fields.

Zinc and lead sulphide scales became an increasing challenge in oil and gas production. More specifically when formed from wells producing under very severe conditions of high temperature (196°C/282 °F) and high salinity formation waters such as those experienced in Central Graben Fields, their prevention by conventional scale inhibitors has proved challenging. To date after extensive chemical qualification over several years, no conventional scale inhibitor has been found which can both inhibit lead and zinc sulphide and survive under the extreme conditions of these fields. Therefore, the results in this paper represent a significant advance in the ability to control sulphide scales and test the inhibition under appropriate conditions.
Efficient Si Removal from Recycled Water for Steam Injection Using Unique Electrocoagulation Process
Authors: Cao Jiasheng , Monroe Steve
Published: April 2015

In many areas water used for steam flood injection has varied concentrations of dissolved silicon (Si), which can form silica scale, reducing thermal efficiency, and lowering steam quality. Scale inhibitors are typically used today, but removal of Si may be a more cost-efficient process to reuse the water, especially in areas with limited fresh water availability. Removing Si in the water treatment plant before steam generation can lead to higher quality steam at lower costs and result in better production.

Typical chemical precipitation methods have been reported for Si removal by adding different coagulant compounds that contain elements such as aluminum (Al), iron (Fe) or molybdenum (Mo). In general, the chemical precipitation method needs high volumes of coagulants and generates considerable amounts of sludge, and may also input extra compounds or ions into the treated water. Electrocoagulation (EC) has been claimed for Si removal, but low conductivity water (or low concentration of total dissolved salt (TDS)), as seen in steam injection systems, is not well-matched to traditional EC systems.

In this paper, a uniquely designed electrocoagulation (EC) system with non-sacrificial electrodes and sacrificial material was tested for Si removal from steam injection water. This EC system has been shown to be highly flexible and efficient for treating waters with TDS levels from 3,000 to over 300,000 mg/L, especially for Si, Fe, and suspended solid removal. The water in this case was hot (180°F), low TDS (<6,000mg/L), and had 60 to 80 mg/L of Si. Both laboratory scale testing and pilot field trial showed efficient Si removal from the water to less than 2 mg/L at varied temperatures. Significant hardness removal was also achieved during the same process. Compared with chemical precipitation methods, this unique EC system used fewer chemicals, generated less sludge, and provided a higher quality of effluent water.