In this study, a novel surfactant for flowback aid application was developed based on an optimization of well-known non-ionic surfactants. The objective was to meet intrinsic surfactant properties, such as high cloud point (CP), low surface tension (ST), adequate contact angle (CA) and low critical micelle concentration (CMC). In addition to the essential physical-chemical properties, improvement in fluid recovery and emulsion compatibility were also targeted. The surfactants were optimized by tailoring the hydrophilic head through controlled introduction of ethylene oxide and propylene oxide into different hydrophobic chains. Surface tension measurements were made with a Dataphysics Instruments model OCA-15. Contact angles were measured using the sessile-drop method. The CMC concentration and cloud point were also conducted for physical chemical characterization. For the fluid recovery evaluation, flowback solutions were poured through 150g of 60/150 mesh- dry porous media contained in a 7 cm-inner-diameter, 9.5- cm-long column. Emulsion compatibility tests were also carried out using different proportions of crude oil and brine. This paper evaluates various flowback additives in hydraulic fracturing applications between linear and branched alkoxylated surfactants. High cloud point enables a wide range of temperature applications and an increase in EO content showed an increase in cloud point values, contrary to PO effect. Nevertheless, CMC measurements showed that for an optimum scenario, EO addition should not be high, because undesired increases in CMC values may occur, which will affect the final surfactant dosage needed. All flowback aids demonstrated low surface tension as expected (approximately below 32 mN/m), but each being different in terms of surface wettability (contact angle), which could not be correlated with surfactant structure. Fluid recovery and kinetics of emulsion breakage increased significantly with different alkoxylation adjustments. For the new flowback aid developed, the fluid recovery was improved when compared against standard surfactants. Additionally, significant improvement was also found during emulsion breakage evaluation in terms of superior kinetics, final breakage, and water quality. This work provided a better understanding of how EO/PO affects intrinsic surfactant properties and enabled to find a surfactant that offers several benefits in terms of fluid recovery and non-emulsification of crude oil and water.

Hydraulic fracturing presents an ideal breeding ground for microbial proliferation due to the use of large volumes of nutrient-rich, water-based process fluids. Bacteria and/or archaea, when left uncontrolled topside or in the reservoir, can produce hydrogen sulfide, causing biogenic souring of hydrocarbons. In addition, microbial populations emerging from the downhole environment during production can colonize production equipment, leading to biofouling, microbially influenced corrosion (MIC), produced fluid separation issues, and HS&E risks. Mitigating these risks requires effective selection and application of biocides during drilling, completion, and production. To this end, a microbiological audit of a well completion operation with the objective of determining the effectiveness of a tandem chlorine dioxide (ClO 2 ) and glutaraldehyde/quaternary ammonium (glut/quat) microbial control program was carried out. This paper describes the rationale behind selection of sampling points for a comprehensive microbiological field audit and provides the resulting critical analysis of biocide efficacy in the field using molecular assays (qPCR, ATP) and complementary culturing techniques (microtiter MPN and culture vials—commonly termed "bug bottles"). Due to the comprehensive nature of sampling and data collection, it was possible to make much more applicable and relevant observations and recommendations than it would have been using laboratory studies alone. First, multiple sources of microbial contamination were identified topside, including source waters, working tanks, hydration units, and guar. Additionally, critical analysis of biocide efficacy revealed that ClO 2 treatment of source water was short-lived and ineffective for operational control, whereas glut/quat treatment of fracturing fluids at the blender was effective both topside and downhole. Analysis of the microbial load at all topside sampling points revealed that complete removal of ClO 2 treatment could be offset by as little as a 10% increase in glut/quat dosage at the blender. This is a highly resolved microbiological audit of a hydraulic fracturing opration which offers new, highly relevant perspectives on the effectiveness of some biocide programs for operational control. This overview of biocide efficacies in the field will facilitate recommendations for both immediate and long-term microbial control in fractured shale reservoirs.

The performance of a new synergistic biocide combination based on glutaraldehyde and THNM (tris (hydroxymethyl) nitromethane) was extensively evaluated in laboratory trials using water samples from twenty-six Brazilian and Argentinian oilfields. The performance was ultimately validated in four field trials, two per country (A1, A2, B1, B2), over a three month duration. For laboratory tests, water samples were collected from numerous locations of the various oilfields and characterized/enumerated by serial dilution (SRB and APB bug bottles), ATP, and molecular biology techniques (NGS). Water and isolated indigenous SRB/APB from the most contaminated locations were used as the matrix and test inoculum for the biocide optimization tests. Numerous biocide systems, at total active ingredient concentrations ranging from 111 to 250 ppm, were evaluated by assessing the ability to rapidly kill the native organisms (2 hour contact time at room temperature) and protect the water from contamination over a prolonged time frame (≥7 days) under heat-aged conditions (60°C). Results demonstrated that glutaraldehyde/THNM provided the best performance in the majority of the samples evaluated and was therefore selected for performance evaluations in field tests owing to the enhanced performance of this particular treatment in the laboratory. Field trials were conducted by applying the lowest total biocide concentration that demonstrated a ≥ 4 log 10 microbial reduction (in the laboratory studies) at various problematic field locations. All biocides were dosed as batch treatments 2-3 times per week (2-3 hours per treatment). Specifically, the co-dosed glutaraldehyde/THNM combination replaced incumbent treatments of either THPS or glutaraldehyde (batch dosed) in combination with a quaternary ammonium compound which was being applied by continuous injection: Field trial B1 – Results showed a significant reduction in bacterial counts at the farthest injection well (12 km from the point of biocide application). Total anaerobic bacteria levels were reduced from ~10 6 CFU/mL to less than 10 2 CFU/mL after 1 month treatment. Additionally, total biocide consumption was reduced by 24% as compared to the incumbent biocides traditionally applied. Field trial B2 – Following treatment of injection water, SRB results showed a reduction at the farthest injection well (30 km), from 10 3 cells/mL to 10 1 cells/mL, after 3 months treatment. Field trial A1 – After applying glutaraldehyde/THNM to production and injection water, SRB/APB levels were reduced (~10 8 CFU/mL to 10 2 CFU/mL) at the farthest injection well (7 km) after 1 month treatment. Field trial A2 – Following the treatment of production and injection water, all monitored points demonstrated a reduction of SRB counts from ~10 7 CFU/mL to 10 2 -10 3 CFU/mL after 6 weeks. Furthermore, in the B1 and A1 trials, NGS results indicated a shift of the microbial population to less harmful (non-MIC relevant) organisms. Overall, the novelty of this biocide combination is its ability to provide strong, broad-spectrum antimicrobial performance and long-term effectiveness, as compared to traditional biocide chemistries.

Microbial-induced problems in oil and gas incur high costs and cause severe environmental and safety concerns. Most of these problems are directly caused by surface-adhered bacteria colonies known as biofilms. Distinct populations of bacteria within a biofilm can symbiotically alter surrounding conditions that favor proliferation to the extent that leads to corrosion, plugging, and H 2 S souring. Biocides are antimicrobial products used to eliminate and prevent bacterial growth. The purpose of this initial study is to measure performance of biocides against anaerobic planktonic and sessile bacteria. The three anaerobic conditions tested were biocide performance against planktonic bacteria, against established biofilm, and inhibition of biofilm growth. Biocides containing two types of quaternary ammonium compounds and blends with glutaraldehyde were evaluated against sulfate reducing bacteria (SRB) and acid producing bacteria (APB) in both planktonkic and sessile forms. As expected, all of the biocides tested were effective against planktonic bacteria. Quaternary type biocides were found to be particularly effective at controlling sessile anaerobes. Surprisingly, the addition of glutaraldehyde did not appear to provide synergistic benefits and actually had a negative dilutory effect on the performance against biofilms. In all cases, dialkyl dimethyl ammonium chloride (DDAC) was the most efficient biocide in controlling all bacterial forms tested, both planktonic and sessile.

The controlled release of scale inhibitors (SI) and other treatment chemicals in the near-wellbore region is a key strategy to improving water management and extended well production. In addition, during some completion and stimulation operations, it is desired that robust particles providing controlled release be placed in gravel and sand packs. A novel controlled release scale inhibitor particle is presented which provides beneficial properties due to its unique chemistry and polymer processing methods. This technology provides extended feedback of scale inhibitor with tunable release rates.

Viscoelastic surfactants (VES) are important gelling agents in well stimulation treatments. Proper job design requires that the additives create the desired viscosity for effective proppant or gravel pack sand transport. Post-stimulation production enhancement partially relies on the thoroughness of gelling agent destruction or removal, known as "breaking" the gel. VES gels are non-damaging and do not create a filter cake, and thus are prone to high leak-off. The leak-off fluid potentially has a high zero-shear viscosity and can be challenging to remove from the formation. We propose a breaker system that comprises a monomer and radical initiator that will travel into to the formation with the VES gel. The resulting polymer will disrupt the worm-like micelles of the VES, creating spherical micelles and reducing the viscosity of the fluid. The breaker system presented here is operable at 200 °F. Rheology measurements show that the VES fluid with monomer and initiator has reduced viscosity and becomes less shear-thinning. Optical transmission and backscattering measurements show that the presence of breaker does not greatly accelerate proppant settling. The reduced viscosity would not adversely affect proppant transport. Core flow experiments compared retained permeability of cores treated with VES and VES with reacted monomer and initiator. The core flushed with broken fluid possessed a retained permeability of 79%, while the unmodified VES left only 44% retained permeability.

We prepared physically linked allyl alcohol polymer/polyacrylamide double network hydrogels via one-pot strategy. These double network supermolecular fracturing fluids were found to have a better viscosity at high temperature compared to the conventional polyacrylamide systems. After testing with a rheometer, the fluid viscosity could stay 320 mPa s at 150 °C under 170/s shear rate. With NMR and FT-IR results' help, we determined that abundant polar groups of chains were still free, which could complex ions to keep, even enhance the chain stability. Thus, these double network systems showed excellent salt resistance with the non-covalent interactions and physical entanglements, and the viscosity of the allyl alcohol polymer/polyacrylamide system did not drop but increase. The viscosity in high salinity could increase nearly 40 % compared with the initial situation. Overall, the novel fracturing fluid system could maintain a high viscosity and better rheological properties under high salinity and showed excellent high-temperature stability, to make up the lack of fracturing fluid at this stage. It is expected to potential fluid issues caused by low water quality and harsh downhole temperatures were resolved or mitigated.

Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance. In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and pH are the secondary cause affecting scale formation in the reservoir. During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.

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.

Friction reducers (FRs) are an important component of slickwater hydraulic fracturing applications. Using only a single FR system throughout the entire treatment is highly desired in water sources of salinity varying up to 300,000 ppm. This paper discusses field trials of a new salt-tolerant FR system in the Marcellus shale. A three-well trial program was initiated in the Marcellus. Multiple water sources with varying salinities were used with up to 100% reuse of produced water. The new FR system enabled the pumping pressure to be reduced below 8,500 psi, and the pumping rates were increased and maintained at approximately 100 bbl/min. This new salt-tolerant FR system consists of a water-in-oil cationic polymer and a surfactant inverter. Unlike other FRs, the distinctive advantage of this FR is that the ratio between polymer and inverter can be readily adjusted on-the-fly to achieve maximum friction reduction.

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.

With developing interest in unconventional fields, such as fractured shales, there has been a need to develop models that accurately reflect the fluid-transport mechanisms in such formations. The current paper does this from the viewpoint of modelling scale inhibitor squeeze treatments. Unlike conventional reservoirs, where chemical transport is dominated by pressure differentials from pumping, in ultra-low permeability systems imbibition and diffusion processes can be as important, if not more so. We report a model that numerically solves either the imbibition equation or Fick's second law of diffusion to simulate these transport mechanisms, and couples these processes to inhibitor adsorption and desorption using either Freundlich or Langmuir isotherms. As only a fraction of the production interval is typically treated, the model interactively allows the user to select which fractures have been treated. The influence of partial treatment of the fracture network on overall treatment effectiveness is presented as is the effect of varying entry location of the produced water into the well. The model was also developed to simulate spontaneous imbibition of the aqueous inhibitor solution in combination with inhibitor adsorption, albeit in the absence of diffusion. The effect of this imbibition has been evaluated from the perspective that it acts as a potential "treatment thief" because it preferentially transports the applied inhibitor solution into oil-producing zones, whence it should contribute very little to mitigation of the current scaling risk.

Multi-pad hydraulic fracturing is believed a cost-effective procedure to unlock the tight oil from low-porosity, low-permeability reservoirs. However, the inconvenience of difficult-dissolving process at surface and crosslinking of the conventional guar-based fracturing fluid systems cannot satisfy such fracking jobs because of the massive proppant loading, high flow rate and large volume of the fluids used. To address these issues, a crosslinking-free and rapid-dissolution fracturing fluid system based on synthetic hydrophobically associating polymer (HAP) "water-in-oil" emulsion was developed. The HAPs are derived from classical water-soluble polymers by incorporating small amount of long hydrophobic side chains onto the polymer backbone. When above a critical associating concentration, these polymers can automatically form a three-dimensional transient network by intermolecular association, reminiscent of cross-linked structures, offering the suspending capacity for proppants. With inverse emulsion polymerization, the obtained HAP emulsions can not only get high molecular weight, but also be rapidly dispersed and finally dissolved within 5 minutes. It was found concentrated HAP polymer emulsions can be dispersed online with surface water or even produced fluids to get final designed concentration. Laboratory rheological study shows that 1% of the as-prepared fracturing fluid can reach more than 50 mPa%s at 150 0C. Compared with guar-based fluid, the HAP fracturing fluid can be completely broken, and the viscosity, surface tension, skin damage of the residual fluid on the permeability are all smaller, while the fluid loss is comparable, proppant-carrying ability is even better. Most importantly, no further surfactant was needed to assist the flowback the fluid. Since September 2013, such associative polymer fracturing fluids were successively used in 29 wells of 3 well pads, Yan-227, Yan-22 and Bin-37 blocks in Shengli Oilfield, Sinopec, where the temperature ranges from 110 to 145 cC. Totally 60,000 m 3 fluids were consumed in these fracking jobs, and 87, 9, and 45 stages were successively fractured in the horizontal sections, respectively.

To maintain open and conductive fractures in tight-rock shale formations, shale/water interactions should be controlled through chemical or brine treatments. Adequate treatment of an unconventional formation can mitigate or reduce the damaging effects induced by shale (swelling, sloughing, fines migration) or proppant (proppant embedment, breakage, fines migration), which leads to maximized conductivity. This study characterizes shale behaviors with various treatment fluids applied under simulated downhole conditions. Four source rock shale samples, Barnett, Eagle Ford, Mancos, and Marcellus, were characterized and evaluated in contact with chemical and brine treatments to determine the extent of swelling and mechanical stability imparted by each treatment. Conductivity measurements were taken on proppant packs between shale wafers under closure stresses from 2,000 to 10,000 psi. The wafers used during those tests were then analyzed using computed tomography (CT) imaging. Quantification and classification of the damage were used to evaluate the shale formations after application of fresh water and two chemical treatments—a small cationic oligomer and a large cationic polymer additive. Results suggested that chemical and brine treatments do not provide an all-inclusive mechanism to prevent damage for all shale samples, and total clay content or clay type was not the best predictor of water sensitivity. Barnett shale samples contained the most clay, had the highest conductivity, and were most resistant to fluid-induced damage using a small cationic oligomer additive. Conductivity loss for the other three shale formations was primarily attributed to fluid-induced formation damage. In each of these three shales, the mechanism for formation damage resulted from different causes. Clay-induced swelling for Mancos shale resulted in the most significant proppant embedment and was most effectively remedied using a large molecular weight polymer stabilizer treatment. Eagle Ford and Marcellus shales showed pockets of proppant embedment and significant fines migration. Generation of migrating fragment causality was different for these two shales; one contained migrating clays in its mineralogy, while the other was more mechanically brittle and prone to stress-induced fragmentation. The differing mechanism changed the effectiveness of the chemical treatments; Eagle Ford shales were most responsive to large molecular weight polymer stabilizers, whereas Marcellus shales did not change significantly with the chemical treatments evaluated. Selecting the optimal chemical treatment for each formation depends on the mechanism and type of damage. Each reservoir is unique, and improving production begins with customizing treatments to protect the formation materials against the specific damage mechanisms, thus minimizing the negative impact on propped fracture conductivity. Understanding the exact needs of each shale formation allows the treatment fluid to be tailored specifically for the formation as part of the fracturing treatment design, thereby optimizing the treatment effectiveness and cost.

In oil and gas wells that are hydraulically fractured, wetting properties of surfaces (formation and proppant) significantly affect hydrocarbon and liquid displacement. During the life of a well, the water saturation of surfaces changes, leading to reduction of relative permeability to oil or gas and consequently affecting production. In order to reverse the formation to a reduced water wet state and improve the movement of hydrocarbons, strong water-wet surfactant is pumped. The surfactant is then adsorbed onto the surfaces reducing the capillary pressure and water saturation within the porous systems. This is, however, not a permanent solution, as the surfactant is washed out over time. A more permanent and robust solution is needed. Nature encompasses many examples of biological systems and surfaces that are permanent and have special wettability and interfacial interaction with fluids. Research and development within the last decade in bio-mimicking nature has been fruitful and led to the development of many new surfaces such as superhydrophobic, ice phobic and low-drag surfaces. In this work we apply some of the knowledge and principles found in nature to modify proppant surfaces (silica sand and ceramic proppant) in order to study how wettability will affect the fluids recovery and their interaction with the solid surfaces. Nanotechnology was used to deposit hydrophobic/oleophobic moieties onto the proppant surfaces, and several surface modifiers were tested. These molecules were covalently bonded to the surfaces. The new surfaces were characterized for wettability and flow to water and oil. A new proppant that show promises for improved stimulation fluids recovery and flow was identified and further developed.

During hydraulic fracturing operations in oil wells, the equilibrium balance of the crude oil is disrupted once high-pressure fluids are injected into the formation. Fluid temperature is often less than reservoir temperature, and if the formation is cooled below the cloud point, paraffin precipitates may deposit in the formation pores and faces as fractures develop. For paraffin-rich reservoirs, such as shale oil, damage caused by wax deposition at the fracture skin can cause decreased production, slow or hard to clean up wellbores, or failure to achieve predicted maximum recovery. Developments in horizontal drilling and hydraulic fracturing during the past decade provided the industry with a versatile tool that utilized fracturing fluids as a carrier to deliver chemical additives in the form of liquids or solids deep into the reservoir. Chemistries, such as scale, wax and asphaltene inhibitors, are impregnated or infused in porous solids and placed into fractures during the fracturing job, which can provide long-term well protection and production control. Water-soluble additives can be easily formulated within these fluids and/or delivered via slow-release solid products, but the delivery of water-insoluble additives are difficult on an equivalent base. Non-polar additives are not going to be released from solid carriers since the water cut is relatively high within one to four weeks of a hydraulic fracturing job. The risk of organic deposition persists if minimum inhibition concentration of chemical additive is not attained during and after the job. The scope of discussion in this paper will largely focus on water-dispersible systems, in particular to colloidal microdispersion, since they are the most prevalent type of dispersions found to be viable for hydraulic fracturing applications. A methodology is presented that demonstrates the advantages of water-dispersible wax inhibitors that prevent paraffin deposition from waxy crudes in the Bakken, Permian and Eagle Ford basins while complementing long-term control further provided by solid wax inhibitors. This study adapted a novel approach by incorporating wax and paraffin control chemistries into a microdispersion system that is fully dispersible in water. In such micron-sized liquid-in-liquid or solid-in-liquid colloidal dispersed systems, active chemistries comprising polymers from poly (EVA), poly (alkylacrylate), poly (EVA-alkylacrylate), poly (α-olefine-MAA) esters/amides/imides, and selected dispersants and surfactants are brought together to deliver immediateand short-term inhibition for paraffin wax control.

Nanomaterials are being implemented in more and more industries due to their unique properties and performances at the nanoscale. In the oilfield, nanomaterials can significantly improve the performances of well treatment fluids including hydraulic fracturing fluids. Fluids based on polymers such as polysaccharides are widely used in the oilfield as fracturing fluids, but these fluids can have some limitations. For example, high molecular weight and incomplete breaking of these polymers can cause serious formation damage. An alternative material is viscoelastic surfactant (VES) which has been used for fracturing and acid jobs. VES-based fluids are low molecular weight in nature and show minimum formation and conductivity damage. Yet, there remain challenges associated with their use such as limited thermal stability and high leakoff rate. The use of nanomaterials such as MgO and ZnO was found to enhance their thermal stability and leakoff properties at temperatures up to 250°F. For wells with higher bottomhole temperatures, the nanomaterials that can significantly enhance the performances of the VES fluids at 350+°F will be much sought after. In this paper, we report the use of a number of the selected nanomaterials to enhance the VES gels at temperatures up to 350°F or higher. In one example, the addition of about 0.1 wt% nanomaterial-I enhanced the viscosity of the VES fluid by about 24% averaged over the temperature range from 250 to 350°F. In another example, nanomaterial-II at a dose of about 0.04 wt% enhanced the viscosity of the VES fluid by about 23% averaged over the temperature range from 250 to 350°F. Additionally, measurements showed that the viscosity of the VES fluids remained above 110 cP (at 100 s -1 shear rate) for over two hours at 350°F with the addition of either nanomaterial-I or nanomaterial-II. The fluid stability at elevated temperatures could also be improved with the selection of other nanomaterials. This paper will discuss the applications for these nanomaterials in hydraulic fracturing and other oilfield operations under high temperature conditions, based on the laboratory test results that will be shared in detail. This technology could open the door for more advancement in hydraulic fracturing with non-damaging VES systems at high temperatures.

Contamination of oil and gas operations by sulfate-reducing prokaryotes acid-producing prokaryotes, and facultative anaerobic prokaryotes can significantly reduce hydrocarbon quality, compromise asset integrity, and cause plugging in the formation. Complete treatment of these contaminants requires the use of biocides capable of retaining efficacy in the extreme conditions common in deep subsurface wells. This study investigates the interactions of several common oil and gas biocides with shale to determine their suitability for use in the downhole environment. Each biocide was submitted to studies analyzing (1) shale's effect on chemical stability and aqueous availability of the biocides, and (2) resulting biocidal efficacy on common facultative anaerobes. The chemical availability study was performed using high performance liquid chromatography, and the comparative biocidal efficacy study was performed using standard microbial viability assays. Due to variances in complexity of hydraulic fracture networks, the degree of adsorption was also measured as a function of shale surface area. The panel of biocides showed a variety of responses to exposure to shale. Surface-active, cationic biocides rapidly associated with shale preferentially over water, significantly reducing the availability of these compounds in the aqueous phase. Accordingly, their efficacy against planktonic bacteria substantially diminished. Across the range of shale types (surface area and reservoir source) tested, all surface-active biocides lost efficacy. Most biocides that rely on electrophilic reactivity (rather than surface activity) for efficacy against microorganisms showed little to no interaction with solid shale, and biocidal potency was not compromised. These results provide guidance for selection of biocides that will remain stable, chemically available, and ultimately efficacious in the extreme conditions of a subsurface shale reservoir.

The Eagle Ford formation, often referred to Eagleford Shale , is a complex one. Some field personnel involved with drilling this formation argue that in their experience Eagle Ford formation is not "shale" at all; however, they do not offer a morphological, mineralogical, and mineralogical reason supporting their claim. To design, plan, engineer, and carry out an economically viable drilling, completion, and production, we need a deeper understanding of both general and local characteristic of the Eagle Ford formation, whether shale or not! Following this goal, with the help of industry, we received on loan, full cores of Eagle Ford formation, and began our tests and analysis. Using an interdisciplinary approach, it is the object of this paper to characterize the formation in depth. Having learned from our several decades of shale studies, our analyses include but are not limited to: (1) determining solubility of Shale specimen in de-ionized water, (2) using ion selective electrodes, measure the potential, Eh, Temperature, and Hydraulic Potential over the submerged portion of specimen, (3) setting up a video system to record all measurements with time to see (a) which ion leaves the mass of specimen first at a given instance of time and (b) to see whether the timing of this event coincides with the release of first bubble of gas and appearance of fractures in the shale mass, (4) analyzing the slopes of Eh vs. Time (5) examining the possible beneficial and non-beneficial effects of bacterially produced minerals, i.e. combined carbonate-silicates, Marcasite/Pyrite (FeS 2 ), on hydrocarbon development in source rock, and finally (6) determining how these interactive, bio-geo-chemo-systems could affect the mechanical properties of the Eagleford formation. Our results show: (a) Na + diffuses from specimen to water first, almost instantaneously, next is Ca +2 , from ½ to several-hours, and Mg +2 up to 20-hours, (b) gas bubbles appear about 0-2-hours after Na + release, (c) time for ionic permeability to reach equilibrium (steady-state) is within the range of 20-50 hours depending on the concentration of and type of release of, (d) pH remains acidic between 5.5 and 6.5, (d) diffusion of Na ion from specimen to water appear to initiate first at the pressurized fissility planes (planes of weakness), which is rapid at the beginning but slows down thereafter, possibly indicating activation of the small and smaller pores in the specimen, (e) the bacterium, shown by arrows in Fig 10 , converts Fe II to FeIII then to Marcasite crystals, along with secretion of associated minerals, where these minerals could act as thermal insulator and allowing maturation of the hydrocarbons in-situ to continue, and (f) in this process it appears that the excess supply of H 2 S, the by-product hydrogen, along with growth of crystals, all lead to pressure build-up in the fissility planes, thus prying them open. The Shale plates, due to dissolution of cement bonding them, appear unable to bond back, which could be attributed to the presence of water and sulfuric acid, reacting with the rock material, rendering it thin, weak, and brittle. Understanding these results could determine a more favorable drilling strategy for constructing a stable wellbore, mitigating lost circulation, designing a better fracturing method, designing a more compatible completion and fracturing fluid, and implementing better corrosion mitigation while producing the well.

The interaction of oil and gas biocides with critical environmental factors directly affects their performance in applications where successful water management practices are essential. These include hydraulic fracturing, water flooding, and water storage and disposal. Effective control of microbial contamination in these applications is required for the sustained quality of the production fluids and structural assets. The microbial groups of concern are sulfate reducing bacteria (SRB), acid-producing bacteria (APB), and facultative anaerobes. In this study, representative oxidizers and non-oxidizers were tested under environmental parameters of importance including elevated temperature, biological organic matter, and individual process additives (xanthan, guar, polyacrylamide). These parameters represent common conditions which may be present and should be considered when selecting a biocide treatment. Results showed that all biocides have inherent antimicrobial activity versus SRB and APB. The stability and compatibility of these biocides varied widely. Oxidizing biocides, in general, showed good efficacy at low concentrations at room temperature. However, the oxidizers showed poor stability and a loss of activity at elevated temperatures (>40° C). By contrast, several non-oxidizing biocides showed very good stability and efficacy at significantly higher temperatures (60-80° C) providing microbial control for weeks to months. The addition of organic matter and process additives had little effect on the non-oxidizing biocides; however, certain oxidizers were rapidly inactivated and showed varying interaction with the additives. Understanding the compatibility and stability of biocides is critical to their performance and essential to define microbial treatment strategies to provide both rapid topside kill with extended downhole control under typical reservoir conditions.