bluuebunny/crossref_metadata_2025 huggingface dataset:
Drivers of nitrogen dynamics in ecologically based agriculture revealed by long‐term, high‐frequency field measurements
Authors: Finney Denise M. , Eckert Sara E. , Kaye Jason P.
Published: April 2015

Nitrogen (N) loss from agriculture impacts ecosystems worldwide. One strategy to mitigate these losses, ecologically based nutrient management (ENM), seeks to recouple carbon (C) and N cycles to reduce environmental losses and supply N to cash crops. However, our capacity to apply ENM is limited by a lack of field‐based high‐resolution data on N dynamics in actual production contexts. We used data from a five‐year study of organic cropping systems to investigate soil inorganic N (SIN) variability and nitrate (NO3−) leaching in ENM. Four production systems initiated in 2007 and 2008 in central Pennsylvania varied in crop rotation, timing and intensity of tillage, inclusion of fallow periods, and N inputs. Extractable SIN was measured fortnightly from March through November throughout the experiment, and NO3‐N concentration below the rooting zone was sampled with lysimeters during the first year of the 2008 start. We used recursive partitioning models to assess the importance of management and environmental factors to SIN variability and NO3− leaching and identify interactions between influential variables. Air temperature and tillage were the most important drivers of SIN across systems. The highest SIN concentrations occurred when the average air temperature three weeks prior to measurement was above 21°C. Above this temperature and within 109 days of moldboard plowing, average SIN concentrations were 22.1 mg N/kg soil; 109 days or more past plowing average SIN dropped to 7.7 mg N/kg soil. Other drivers of SIN dynamics were N available from manure and cover crops. Highest average leachate NO3‐N concentrations (15.2 ppm) occurred in fall and winter when SIN was above 4.9 mg/kg six weeks prior to leachate collection. Late season tillage operations leading to elevated SIN and leachate NO3‐N concentrations were a strategy to reduce weeds while meeting consumer demand for organic products. Thus, while tillage that incorporates organic N inputs preceding cash crops can promote synchrony of N mineralization and crop demand, late or post‐season tillage promotes NO3− leaching by stimulating SIN pulses that are asynchronous with plant uptake.
Application of Novel Polymer Assisted Emulsified Acid System Improves the Efficiency of Carbonate Acidizing
Authors: Zakaria A. S. , Nasr-El-Din H. A.
Published: April 2015

In highly heterogeneous carbonate reservoirs, several acid systems have been used to enhance acid distribution during matrix acidizing. Gelled acids are commonly used to improve the wellbore coverage. However, the injection of such acids at low rates and high temperature has a negative effect on spending rate, initiates filtercake formation which inhibits the wormhole growth, can cause formation damage and has high corrosion rates. This paper presents an innovative formulation for emulsifying the gelled acid (polymer assisted emulsified acid) for better acid treatments at high temperatures.

The objective of this work is to investigate the behavior and the performance of a new innovative acid system: polymer assisted emulsified acid as a self-diverting acid by conducting viscosity measurements, reaction rate experiments, thorough coreflood study, and acid diversion experiments. The system was 15 wt% gelled acid emulsified in diesel with 70:30 acid/diesel volume ratio.

Coreflood experiments were conducted at 230°F at different injection rates on low and high permeability Indiana limestone. Also, a 0.5 PV of the polymer assisted emulsified acid was injected to assess the effect of the acid on the permeability of the cores before breakthrough. Finally, two acid diversion experiments at 1 cm3/min were conducted into pairs of low and high permeability cores to test the effect of polymer concentration in the acid internal phase on diversion.

The viscosity measurements and acid diffusivity measurements showed that increasing the polymer concentration in the internal phase of the emulsified acid from 0 to 1.5 vol% enhanced significantly the viscosity of the emulsified acid and reduced the diffusion coefficient by one order of magnitude.

Coreflood results showed that the polymer assisted emulsified is an effective wormholing fluid at low injection rate while maintaining the high viscosity of the acid system for zonal coverage. Also, it was shown that the emulsion/polymer retention is the main source for permeability damage. However, flowback with mutual solvent removes any remaining damage and permeability enhancement is achieved

Acid diversion experiments were presented that show the self-diverting ability of the polymer assisted emulsified acid into the low permeability cores.
Corrosion and Scale Formation in High Temperature Sour Gas Wells: Chemistry and Field Practice
Authors: Ramachandran Sunder , Al-Muntasheri Ghaithan , Leal Jairo , Wang Qiwei
Published: April 2015

Sour gas is being produced from a number of carbon-steel-completed wells in the US (Mississippi, Alabama), Canada, France and Saudi Arabia. The gas stream contains various levels of hydrogen sulfide, carbon dioxide and is produced from high temperature reservoirs (with temperatures ranging from 160 to 410°F). The combination of hydrogen sulfide with high temperatures introduces challenges related to corrosion and iron sulfide (FeS) scale formation. The thermodynamics and kinetics of iron sulfide formation will be reviewed. There is a large literature on the thermodynamics and kinetics of iron sulfide scales in the context of corrosion of mild steel. High temperatures and high concentration of hydrogen sulfide favor the formation of pyrrhotite and trolite which are an order of magnitude less soluble than cubic FeS or mackinawite. Saudi Aramco has been producing sour gas from deep carbonate reservoirs since 1984. The mole percentage of hydrogen sulfide (H2S) in the gas of these wells range from 1 to 23, while the mole percentage of carbon dioxide in the gas range from 3.7 to 8. Bottomhole temperatures vary from 265 to 320°F. Corrosion inhibition treatment has been sporadic. Chemical and mechanical methods of scale removal have been used in different wells. In a specific instance, the amount of scale has been measured from a given well and the composition has been noted as a function of depth. Assessment about the amount of scale and the potential sources of iron will be provided. Thermodynamic studies of iron sulfide scales will also be reported to explain some of the field observations. The paper provides a summary of the current fundamental understanding in iron sulfide scale (FeS) and corrosion kinetics. It reveals that many oilfield operators do have special stimulation procedures for these wells. These include: special acid stimulation packages, well pickling and processes for continuous injection of corrosion inhibitors to mitigate the iron sulfide scale problems. Results and analysis concerning corrosion and scale problems for specific wells in deep hot gas wells will be presented. The paper will provide a reference point for iron sulfide scale problems in high temperature sour gas wells and for future development in the area.
Achieving Water Quality Required for Fracturing Gas Shales: Cost Effective Analytic and Treatment Technologies
Authors: Burnett D. B. , Platt F. M. , Vavra C. E.
Published: April 2015

Shale gas development relies heavily on multi-stage hydraulic fracturing (HF) to maximize the economic viability of each new well. Industry is making a concerted effort both to recycle and re-use produced brine from fracturing operations and to use alternate water sources for well operations. Some experts foresee almost all produced brines being treated and reused within the next five years. Texas A&M Global Petroleum Research Institute (GPRI) has been one of the leaders in promoting new technology to reach these goals. In the past decade we have conducted a number of field trials in different shale plays to a) identify technologies and determine their effectiveness, b) field test advanced monitoring and measurement techniques, and c) integrate the technologies into one cost-effective program for the industry.

This paper presents results from these trials that compare different types of filtration media used to remove hydrocarbons, filtration techniques to remove suspended solids and nano filtration materials to stabilize ultrahigh salinity brines making them compatible with today's fracturing fluid designs. In addition to describing cost effective brine treatment, we have provided a venue for testing advanced analytical techniques that provide rapid ways to measure the effectiveness of such water treatment. Measuring hydrocarbon content in the brines aids in selection of optimal treatment and monitoring of its effectiveness. New fluid imaging techniques characterize particulates in brines and can help to optimize filtration requirements. Biological monitoring can determine effectiveness of solids removal practices and helps in selection of appropriate bacterial control.

This paper will discuss the need to utilize on-site, real-time analysis of produced water and frac flow back brine to allow faster and more accurate characterization of the oil and gas waters being cycled back to unconventional gas development.

The benefits of the technology come from improved procedures to characterize and mitigate the risks of HF at drilling and hydraulic fracturing sites. Better monitoring and treatment can help to counter the mounting concerns of legislators, regulatory agencies, and the general public as well as aid the economic development of our natural gas resources.
Investigation, Classification and Remediation of Amorphous Deposits in Oilfield Systems
Authors: Eroini Violette , Anfindsen Hilde , Mitchell Anthony F.
Published: April 2015

An increasing incidence of amorphous deposits in both production and water injection systems is causing considerable problems for offshore fields. The amorphous deposits are typically comprised of both organic (biological or hydrocarbon) and inorganic material and can differ considerably in composition.

System deposits of this nature have been previously characterised as ‘Schmoo’ and within our company the descriptive, but non-specific term ‘Black Sticky Stuff’ has been coined. The challenge with use of this terminology is that it makes accurate description of deposits from different systems difficult and does not allow similar materials to be easily categorised.

This paper describes the work undertaken to better understand the composition of samples taken from different systems, both production and injection. Systematic analysis has led to the development of a classification matrix for deposits related to their major components. From the classification, improved knowledge has been gained to enable increased consistency of removal or preventive methods.

Some initial observations are made on an unusual form of deposit - being either a product of, or promoting corrosion - being encountered in water injection systems. The material is causing concern with regard to system integrity and intervention in injection wells. Work to define the root cause, and develop removal methods of this type of deposit is presented.
Hydrodynamic Retention and Rheology of EOR Polymers in Porous Media
Authors: Zhang Guoyin , Seright R.S.
Published: April 2015

Polymer retention caused by increase of hydrodynamic force acting upon polymer molecules was evaluated in this study. The results indicate this hydrodynamic retention is strongly flow rate dependent. In the low-flow region, the retention increases abruptly with increased flow rate. In contrast, in the high-flow region, the increase becomes much more gradual. Our results also demonstrate that this flow-induced retention is totally reversible (no incremental irreversible retention occurs), which is also confirmed by the constant residual resistance factors determined after 100 PV of brine postflush. Consistent with previous literature, distinct flow behaviors of partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers in porous media were observed. For HPAM, in the low-flow regime, Newtonian behavior (i.e., resistance factor is independent of flow rate) was exhibited. In the moderate-to-high-flow regime, HPAM showed shear-thickening behavior (resistance factor increase with flow rate). In contrast, only shear thinning (resistance factor decreases with flow rate) was detected for xanthan polymer. By analyzing the retention and rheology of both HPAM and xanthan polymers, we show that hydrodynamic retention has little effect on polymer rheology in porous media.
Achieving a Stable Native Guar Boron Crosslink in 100% Produced Water
Authors: Lopez Enrique , Nelson Tyler , Bishop Dru M.
Published: April 2015

A specialized fracture fluid system has been developed for crosslinking produced waters recovered from normal oil and gas production using common native guar polymer and boron crosslinkers with a novel pH Stabilizing Agent that mitigates the reaction between high pH buffers and the dissolved solids found in produced water; yielding a stable crosslink to at least 250°F.

This innovative fluid system applies to crosslinking produced water, processed produced water, and flow-back water containing total dissolved solids that typically range from 20,000 ppm to 100,000 ppm and more often containing calcium and magnesium concentrations in excess of 2,500 ppm and 1,000 ppm, respectively.

Currently, the most common crosslinked fracture fluid applied is native guar with a boron crosslinker, however these are limited to use in fresh waters with low calcium and magnesium contents. When boron crosslink guar fluid systems are mixed with produced water, the accompanying high pH buffers and pH modifiers react with the elevated total dissolved solids (TDS) present in produced water - particularly calcium and magnesium. This reaction results in undesirable precipitates that consume the buffer, effectively destabilizing the pH of the fluid at elevated bottom-hole temperatures and preventing a stable crosslink from occurring. And, while an alternative crosslink fluid system - such as derivatized guar with a zirconium crosslinker which is not dependent on pH buffers and pH modifiers - can be used effectively, the economics do not support it. These systems can be expensive and are generally reserved for use in wells with much more complex challenges where the increased costs of these fluids are more easily justified.

This new process will aid in reducing the use of fresh water in fracture treatments by rendering it economically viable for the vast majority of “typical” wells to use produced water, processed produced water, and fresh water not normally considered due to naturally occurring high TDS, with boron crosslink fluids. It will also significantly reduce the water related treatment, transportation and disposal costs associated with produced water.
Reservoir Simulation and Near-Well Bore Modelling to Aid Scale Management in a Low Temperature Development with Multilateral Wells
Authors: Ishkov O. , Mackay E.J. , Vazquez O. , Jordan M.M.
Published: April 2015

This paper presents results of a reservoir and near wellbore modelling study to assist with the evaluation of inorganic scale risk management for a cold sandstone reservoir in the Norwegian sector of the North Sea. Reservoir temperature is in the range 32-48°C and poses a challenge to manage the scale risk.

The field is heavily supported by aquifer water, and the development includes five production wells and seven seawater injection wells. The small number of high-cost, highly productive subsea multilateral wells with long horizontal sections, some with sliding sleeves to enhanced flow management, coupled with a high barium sulphate scaling tendency (up to 350ppm barium concentration in the formation water) requires effective scale management.

This paper addresses questions of timing and nature of seawater breakthrough, when scale inhibitor squeeze treatments will be required, what is the impact of any reservoir reactions between the formation water and injected seawater on the scale risk at the production wells, what squeeze placement profiles look like under a range of squeeze treatment scenarios (various injection rates and sleeve position options). The treatment of multilateral wells by bullhead scale squeeze treatments is not a subject extensively covered in the literature, so the focus of this paper is to understand the impact on squeeze treatment life of bullhead deployment as a function of pump rate with both laterals open and the impact on treatment lifetime and treatment cost of selective placement into each lateral by treating one lateral at a time via activation of the sliding sleeve mechanism.

The paper draws on a wide range of technical inputs to make scale management decisions including: thermodynamic modelling techniques, reservoir simulation of fluid mixing and reaction, laboratory-generated coreflood data to assess chemical selection for scale inhibitor squeeze, and squeeze treatment design drawing on all the information outlined above.

Sharing the scale management technical challenges associated with such low temperatures and treating multilateral wells provides an example of the factors that should be taken into account during project design in similar fields under development in Northern Norway, offshore West Africa and offshore Brazil.
Tandem Acidizing-Corrosion Inhibition with Low Risk-Low Toxicity Chelant
Authors: Beuterbaugh Aaron M. , Reyes Enrique A. , Smith Alyssa L.
Published: April 2015

Temperature plays an important role when acidizing wells using proper acid-stimulation techniques. Typically, with increasing temperatures, stimulation of carbonate formations using hydrochloric acid (HCl) becomes less of a viable candidate for a myriad of reasons, including near-wellbore (NWB) spending and increased corrosion attributed to the aggressive and reactive nature of HCl. While corrosion can be tamed using a proper corrosion inhibitor, NWB spending of the acid cannot be eliminated or reduced without retarding the acid with oil/polymer emulsions or foams. Albeit, efficacy of both has shown to tame this reactive nature, breaking the emulsion or foam can lead to formation damage, incomplete acid spending, or additional pumping stages, all of which add complexity to the treatment.

Herein, a new solid chelating acid is presented, which eliminates many problems typically associated with HCl treatments. This solid acid, when introduced before or in conjunction with an HCl treatment, creates an acid-insoluble filter cake, thus preventing NWB spending. In addition, corrosion testing revealed the solid chelant displays corrosion characteristics similar to aminopolycarboxylic acids and phosphonates, altering the corrosion effects of the HCl acid with tubulars and downhole equipment.

Testing with the solid acid revealed that it can easily be suspended in a gelled HCl acid for placement before or in conjunction with an HCl treatment and exhibits diversionary properties attributed to the small size of the particle entering the pore throats in high permeable matrices. When applied to acid fracturing techniques, core flow testing demonstrated the cake focuses acid spending in a manner resulting in channel-like asperities, rather than broad dissolution of a fracture face. When this technology was applied to matrix acidizing, testing revealed reduced wormhole channel diameter, thus highlighting the effectiveness toward deep matrix penetration of the reactive acid.

In continuance, the filter cake is easily removed with a neutral or alkaline overflush, therefore negating formation damage. Once the filter cake is removed, it exhibits chelation characteristics, thereby retaining spent acid byproducts in solution. This unique property by itself reduces the propensity for recombination of dissolved ions, which can lead to precipitation and possible formation damage.
Formate Brines and their Crystallization Temperatures - New Insight into Fluid Behavior and Measuring Methodology
Authors: Howard Siv , Chrenowski Marcin
Published: April 2015

Ever since formate brines were introduced in the oilfield in the 90's, test laboratories have struggled to determine their True Crystallization Temperature (TCT). The standard API procedure for measuring TCT in oilfield brines simply does not work in formate brines, and it is quite common to see TCT values reported as “too low to measure” even in cases where reference to other studies suggests that the TCT should be well within the measureable limit of the equipment. Factors that complicate the TCT measurements in formate brines are: a) the TCT values can be very low, and may be lower than the cooling capabilities of the measuring equipment, b) an enormous amount of supercooling, and c) the existence of metastable potassium formate crystals that form in formate brines that are rich in potassium formate.

A long-term research program has been aimed at understanding the unusual TCT behavior of potassium formate brine and developing a method to measure the TCT of all formate brines. This research program has delivered an accurate TCT determination procedure for formate brines that is simple, efficient, and involves no specialized equipment. The researchers found that special crystal seeding procedures were needed to get accurate TCT measurements in formate brines. Intelligent crystal seeding eliminates the TCT measurement problems caused by the formation of metastable phase crystals and supercooling.

In addition to full description of an accurate TCT measurement method for formate brines, this paper presents a complete set of TCT values for sodium, potassium, and cesium formate single salt brines and some cesium/potassium formate blends.
Improved Fluid Technology for Stimulation of Ultrahigh-Temperature Sandstone Formation
Authors: Rignol Joel , Ounsakul Thanawit , Kharrat Wassim , Fu Dan , Teng Ling Kong , Lomovskaya Irina , Boonjai Pimterra
Published: April 2015

Acid stimulation is one of the production enhancement methodologies applicable in both development and exploration fields. Sandstone acidizing requires a sophisticated and well-studied approach to avoid formation damage caused by acid precipitation. Although the industry has made significant technical advancements in treatment fluids over the past decades, high bottomhole temperature still presents one of the biggest challenges.

A new chelant-based fluid system was tailored to stimulate sandstone formation effectively under ultrahigh-temperature conditions. The new system has been evaluated extensively in the laboratory.

Laboratory work included sequential dissolution, chemical analysis, and core flow tests. Both dissolution and core flow tests were conducted up to 400°F with reservoir core samples to simulate the actual reservoir condition and treatment design.

Sequential dissolution results indicated that the new chelant-based system dissolved clay minerals in each sequence without causing silica precipitation due to secondary and tertiary reactions. The increase in the permeability of the reservoir core after core flow tests further demonstrated that the new fluid system is indeed highly effective in removing the damaging clay particles. The major advantage of the new chelant-based system is that it can be pumped in a single stage, which has greatly simplified the field operation and diversion requirement. In addition, because of its mild pH, the new system has low corrosion rate and less tendency to emulsion and sludge formation. This new system is HCl acid free, and therefore it eliminates the high risk of silica precipitation due to reaction with sensitive clays at high temperature. Last, but not least, the chelant fluid is consists of a retarded HF system which enables deeper radial penetration with less near-wellbore deconsolidation and which doubles the effect of clay dissolution and stabilization.
How to Monitor Scale Inhibitor Squeeze Using Simple TRF Tracers
Authors: Martini Matteo , Brichart Thomas , Marais Arthur , Moussaron Albert , Tillement Olivier , Baraka-Lokmane Salima
Published: April 2015

Mineral scale deposition in oilfield reservoirs has caused millions of dollars in damage every year. The most common remedy to the build-up of scale inside well bores and the surrounding reservoir is the periodical “squeeze” treatment by inhibitor additives. The real-time and on-site control of inhibitor concentration during production remains one of the big challenges. Indeed, current techniques of inhibitor monitoring that use elemental analysis appear too complex for an efficient long-term industrial solution. With this in mind, we have developed a simple and accurate method for scale inhibitor quantification in production waters based on the use of time-resolved fluorescence (TRF) tracers. The characteristic luminescence signature (lifetime value, emission and excitation spectra) of TRF tracers allows the reliable tracking of inhibitors additives. Moreover, their long-lifetime luminescence signal can significantly increase the signal to noise ratio thanks to the suppression of organic oil residual background emission. Our experimental tests on produced water collected from different sites confirm the detection of a larger variety of inhibitors i.e. for carboxylates, phosphonates and sulphonates by simple post-chelation with TRF tracers at low concentration. Indeed, the non-fluorescent inhibitor species have been switched to fluorescent compound by the addition of few amounts of tracer in order to be detectable and quantified at sub-ppm concentrations. The coupling between TRF tracers and specific TRF spectrofluorometer apparatus then open new and accurate ways for the online and/or on-site monitoring of scale inhibitors for better risk management of flow assurance during production.
Crosslinking of Guar and HPG Based Fracturing Fluids Using ZrO2 Nanoparticles
Authors: Hurnaus Thomas , Plank Johann
Published: April 2015

Hydraulic fracturing requires the use of highly viscous gels which are achieved by crosslinking guar gum or its derivatives with boron, zirconium and titanium compounds. Commonly used zirconium complexes contain chelate ligands such as e.g. triethanolamine or lactate. While many different Zr crosslinkers have been developed, their working mechanism has not received much attention. In our study, we focused on the crosslinking of guar and hydroxypropyl guar gum (HPG) with Zr(IV) triethanolamine and lactate complexes. Their interaction with the polysaccharides was studied via particle size measurements, spectroscopic methods and transmission electron microscopy (TEM).

It is commonly perceived by the industry that the crosslinking effect of Zr complexes is based on a ligand exchange reaction involving the cis-hydroxyl groups present in guar and HPG. To investigate on this concept, HPG and zirconium lactate were chosen as model system. The polysaccharide and the crosslinker were mixed at low pH where no crosslinking occurred and at higher pH values (> 7) where crosslinking took place. When crosslinking had occurred, IR spectroscopy confirmed that the Zr complexes had hydrolyzed and the lactate ligand had been released suggesting that potentially a ligand exchange reaction had taken place. However, TEM images clearly evidenced the formation of almost monodisperse ZrO2 nanoparticles. Numerous such nanoparticles were found within the gelled HPG. In contrast, when no crosslinking had occurred, almost no ZrO2 nanoparticles could be detected.

Based on the observation that the nanoparticles are responsible for the crosslinking of guar, zirconia nanoparticles were synthesized separately and added to guar solutions. Their crosslinking performance was comparable to that of the Zr lactate complex, thus proving that the nanoparticles induce the crosslinking effect. Additional tests revealed that the size of the ZrO2 nanoparticles is a key factor for their crosslinking effectiveness. Particularly small particles (d ~ 3 nm) are most effective while larger particles (d ≥ 10 nm) no longer can crosslink guar.
Application of a Novel Method for Real-Time Monitoring of Scale Control Products at the Site of Use
Authors: Johnstone James , Peltokoski Brita , Toivonen Susanna , Griffin Rick , Hurd Michael , O'Brien Ashleigh , Fournier Frances , Siivonen Joonas , Väisänen Pave , Tittanen Satu , Lehmusto Mirva , Mäkinen Piia , Wahrman Jonas , Mundill Paul
Published: April 2015

Operators in the oil and gas industry make extensive use of scale inhibitors to provide the level of flow assurance required to maximise safe and economic hydrocarbon production. For continuous and scale squeeze treatments, field operators need to verify the residual inhibitor concentrations regularly to ensure that the implemented scale management program remains effective. Sulfonated polymers are effective and widely used sulphate (barium, strontium, calcium) scale inhibitors, however detection of residual (less than 15 ppm) amounts has been problematic, leading to the use of an overdose on continuous applications or resqueezing before reaching the minimum effective dosage (MED) level.

The authors have developed a testing protocol that enables measurement of the residual concentration of polymeric scale inhibitors at the point of use and directly in produced water, providing a timely and accurate scale inhibitor concentration to the facility operator. Field operators with minimal training use sample preparation protocols that are minimized and standardized to determine polymer concentrations within 15 minutes down to 1 ppm active polymer. The testing protocol uses an aqueous liquid fingerprinting technology platform to detect a range of scale inhibitor products and provides direct field analysis for either continuous or scale squeeze application programs. Operators determine the residual scale inhibitor level at the point of use, eliminating the cost and time delay of shipping samples to a remote analytical laboratory.

We previously presented laboratory results of this technology (Johnstone et al. 2014). In this paper, we present the results of the performance of this system in actual field operation which was completed late 2014 at oil and gas production locations and validated at an analytical laboratory. The results demonstrate the benefits of the protocol in field applications in monitoring residual levels to a level of accuracy for polymeric scale inhibitors previously only achievable in fully equipped analytical laboratories.

This technology has been demonstrated to the oil and gas industry and has generated significant interest in a number of communities for which monitoring polymeric scale inhibitors at concentrations less than 5 ppm active is a business-critical activity. The validity of the protocol has been confirmed by ongoing work across a number of application areas, supporting the global industry challenge of scale control.
Propagation of Carbon Nanotube Hybrids through Porous Media for Advancing Oilfield Technology
Authors: Kadhum Mohannad J. , Swatske Daniel P. , Chen Changlong , Resasco Daniel E. , Harwell Jeffrey H. , Shiau Ben
Published: April 2015

Carbon nanotube hybrids (CNTs) have attracted research interest due to their interfacial activity. CNTs can stabilize emulsions and foams and can be used as contrast agents or tracers in rock matrix. In addition, catalytic functionalities can be attached to the nanotubes making them delivery vehicles for catalyst into zones deep inside the reservoir.

Generating stable dispersion of CNTs in harsh reservoir conditions has been the main challenge for utilizing the tubes in in-situ reservoir applications. This is because the dispersed tubes tend to form aggregates that settle down in the presence of high ionic strength (high salinity) brines. In this work, stable dispersion of carbon nanotubes prepared in reservoir fluids is realized by successfully separating individual tubes using such additives as polymers and surfactants. For example, the CNTs would be well dispersed via sonication with highly polarizable polymer such as polyvinyl pyrrolidone (PVP) or Gum Arabic (GA). To mitigating their agglomeration, a secondary additive such as hydroxyethyl cellulose (HEC) polymer is also added to provide adequate steric repulsion for their propagation in porous media at high salinity brines. The nanotube dispersion generated using these dual polymer system is able to deliver successfully through both consolidated cores (200mD permeability of Berea sandstone) and sand pack experiments (4D permeability) with minimal retention at mimic reservoir conditions (65°C and brine compositions of 8% NaCl and 2% CaCl2). Results of the eluted nanoparticles indicate that greater than 80% recovery of injected concentration observed in both consolidated and non-consolidated porous media. Small adsorbed amount of nanotubes is capable of saturating the adsorption sites inside porous media resulting in complete propagation of subsequent injections; this is corroborated by nanotube concentrations approaching 100% of the injected concentration after few pore volumes of injection.

Experiments also demonstrated that in the presence of residual oil inside crushed Berea sandstone sand columns, the extent of nanotubes adsorption to the oil/water interface is a function of the level of oil saturation.

This work is providing insight about the full potential of using carbon nanotubes in oilfield development applications.
First 100% Reuse of Bakken Produced Water in Hybrid Treatments Using Inexpensive Polysaccharide Gelling Agents
Authors: McMahon Blake , MacKay Bruce , Mirakyan Andrey
Published: April 2015

The modern horizontal multistage well is a main contributor to the recent transformation of North American oil and gas production. The large fracturing stage volume that defines unconventional wells, crossed against the increasing numbers of stages and laterals per pad, has dramatically increased the demand for fracturing materials such as sand, friction reducers, and gelling agents, and most especially water. At the same time, operators face increasing accumulations of produced water, which presents as water cut from more mature assets. It is therefore natural to propose using produced water as mixwater for fracturing fluids in new completions, but in practice this plan has met with two major barriers: first, regulatory and logistical hurdles concerning the storage, handling, and potential environmental impacts of the volume of produced water required to complete a modern well (millions of gallons per lateral), and second, technology gaps in the applied chemistry of completion fluids, particularly in crosslinked gels.

This paper reports the completion of a two-lateral well in the Williston Basin where produced water, filtered but otherwise untreated, was used throughout the slickwater and crosslinked components of about sixty hydraulic fracturing stages.

Proppant was successfully placed in all perforated zones in the Bakken and Three Forks formations, using a “hybrid” design that employed seven million gallons of water (of which 2.2 million gallons were crosslinked). Production figures for the well are satisfactory, and this is discussed in the context of fluid-related completion quality. This paper will concentrate on the development and implementation of a metal crosslinked fracturing fluid that shows excellent stability at typical Bakken conditions. We will present a comparison to conventional guar-borate systems.

The promise of this approach has many potential benefits. First, completion costs are decreased as freshwater sourcing and produced water disposal charges cancel each other. Second, far fewer truck trips are necessary to transport water. Third, the industry no longer requires fresh water sources or disposal wells where this technique is employed.
Low Salinity Surfactant Flooding – A Multi-Mechanistic Enhanced Oil Recovery Method
Authors: Tavassoli Shayan , Korrani Aboulghasem Kazemi , Pope Gary A. , Sepehrnoori Kamy
Published: April 2015

We have applied UTCHEM-IPhreeqc to investigate low salinity waterflooding and low salinity surfactant flooding. Numerical simulation results have been compared with laboratory experiments reported by Alagic and Skauge (2010). UTCHEM-IPhreeqc combines the UTCHEM numerical chemical flooding simulator with IPhreeqc, the United States Geological Survey geochemical model. The IPhreeqc model was coupled to UTCHEM to model low salinity waterflooding as a function of geochemical reactions. The surfactant coreflood experiments were done in vertical cores without using polymer or other mobility control agents. These experiments were done at a velocity greater than the critical velocity for a gravity-stable flood. After history matching the experiments, additional numerical simulations of surfactant floods at the critical velocity were run to estimate the performance under stable conditions. We also simulated a surfactant flood at higher salinity with lower IFT and compared the results with the low salinity surfactant flood. These results provide new insights into low salinity waterflooding and surfactant flooding.
Scale Prediction and Control at Ultra HTHP
Authors: Kan A.T. , Dai Z. , Zhang F. , Bhandari N. , Yan F. , Zhang Z. , Liu Y. , Tomson M.B.
Published: April 2015

Production from deepwater environment often encounter ultra high temperature, pressure (ultra HTHP) and with more exotic fluid compositions. Most scale prediction programs were developed by semiempirically modeling the thermodynamic parameters using experimentally measured mineral solubilities and other chemical properties. However, the experimental data were limited at temperature, pressure, and ionic strength that were clearly below that typically encountered in deepwater production. Therefore, extending the existing thermodynamic models to HTHP applications is of questionable accuracy. Furthermore, the partitioning of H2O, CO2, and H2S in and out of the gas/oil phases during production can have a significant impact on scaling tendency. The authors have published papers on experimental solubility measurements and thermodynamic modeling to extend the solubility data to HTHP condition. The new thermodynamic parameters and a flash calculator that integrate the latest development of Equation of State (EOS) to model the partition of H2O, CO2, and H2S in hydrocarbon/aqueous phases at temperature and pressure have been incorporated into a scale prediction software that is specifically tailored for oil and gas production application.

The objective of this paper is to validate the software's application range with a set of critically evaluated peer-reviewed mineral solubility data for general oilfield produced water and deepwater HTHP application. A total of 73 selected papers and more than 2,500 individual experimental data points were included in this evaluation. Our model has been shown to be applicable to greater than 95% of produced water compositions with SI prediction of better than ±0.03 for halite, ±0.05 for gypsum, ±0.1 for calcite and anhydrite, and ±0.2 for barite at temperature between 32 - 500 °F, and and pressure between 14.7 to 22,000 psia. The newly incorporated flash calculator is capable of predicting how CO2, H2S, and H2O partition in and out of the gas phase during production. The partitioning of CO2, H2S, and H2O between the hydrocarbon and aqueous phases has significantly changed the ion composition and pH and therefore, impacted the scaling tendency of the fluids at the production temperature and pressure. This is a particularly important issue for newer wells with high volumes of gas and low water cuts and for CO2 flooding.
Development of a Novel Biofilm Testing Method.
Authors: Keller-Schultz Carrie , Barron-Aldana Jesus , Peter Cruz St. , De Paula Renato M. , Keasler Victor V. , Grieme Linda , Nguyen Duc
Published: April 2015

Several issues associated with microorganisms found throughout the petroleum industry include microbial influenced corrosion (MIC), biotic souring, and biofouling. Traditional methods for evaluating biocide efficacy within the petroleum industry have been focused specifically toward the planktonic, or free-floating, microorganisms. The sessile population, or the community of microorganisms contained within the biofilms that adhere to each other on a surface are not adequately assessed. Since microorganisms contained within biofilms can contribute to all three major microbial issues in the oilfield and the complexity of the microbial community effects the chemical treatment strategy, there is an increased importance associated with the ability to develop a representative, mature biofilm in a lab setting in order to evaluate the efficacy of the chemical treatments prior to implementation in the field. Currently, there are a variety of laboratory methods designed to grow biofilms. However, these methods suffer from many drawbacks. This includes large quantity of fluid required to achieve a once-through system, the number of samples available to test, and the reproducibility of the biofilm growth itself. The purpose of this paper will be to introduce a novel method that will allow for an increased scalability, reproducibility, and utility in laboratory biofilm studies. This knowledge will help in a better understanding of biofilms and facilitate the development of treatment strategies targeting biofilms.
Advances in Tools to Monitor Souring and Corrosion in Oil and Gas Fields
Authors: An Annie , An Dongshan , Elliott Alexander , Menon Priyesh , Shen Yin , Voordouw Gerrit , Cote Dominic E. , Miner Kirk
Published: April 2015

Microorganisms contribute to souring and corrosion in oil and gas field systems. Biocides and/or nitrate can be used to mitigate the negative effects associated with these microbial activities. In order to determine the success of or the need for these measures we use a number of analytical tools on aqueous or solid field samples: (i) spectrophotometric and HPLC assays are used to monitor key analytes (sulfate, sulfide, nitrate, nitrite and others), (ii) microbial assays are used to determine numbers and activities of key microbes and (iii) sequencing of PCR amplicons, typically of a portion of the 16S rRNA genes is used to determine microbial community compositions in field samples. The trick is to combine the information to arrive at a comprehensive view of what is happening and what action may be needed. For instance, a shale gas and a shale oil field in North West Canada, appear to have similar water chemistry. Both are highly saline but halophilic (salt loving) SRB were only found in samples from the shale oil not in those from the shale gas field, which appears related to the different temperatures in these fields of 30-35°C and 75-100°C, respectively. Hence, mitigation measures aimed at killing bacteria downhole may be appropriate for these shale oil but not for these shale gas environments.
Design-support and performance estimation using HYDRUS/CW2D: a horizontal flow constructed wetland for polishing SBR effluent
Authors: Pálfy Tamás Gábor , Gribovszki Zoltán , Langergraber Günter
Published: April 2015

The 4,000 PE (700 m3/d) wastewater treatment plant at Balf, Hungary was based on sequencing batch reactor technology with phosphorus precipitation as the tertiary step. Its effluent met quality thresholds on average, with above-threshold peaks mainly in winter. The HYDRUS/CW2D model package (PC Progress s.r.o.) was used to simulate the treatment performance of a horizontal flow constructed wetland for polishing effluent. The goal of this study was to provide design-supportive information about the suitability of the proposed wetland and to prove the applicability of the computational tool used to gain that information. The simulations showed that the wetland with the proposed layout could not tackle peaks in NH4-N. Other effluent thresholds could be met, including chemical oxygen demand (COD), biochemical oxygen demand (BOD5), total nitrogen, total inorganic nitrogen and total phosphorus. The tool was unable to simulate COD and BOD5 removal in periods when the electron acceptors were depleted because anaerobic processes are not modelled. Using a tool of such complexity for designing carries excessive work demands and involves many uncertainties. The simulation study highlighted that the model used could still facilitate the design of an effective system by showing the weaknesses of a test scenario as it was demonstrated.
Comparative research on phosphorus removal by pilot-scale vertical flow constructed wetlands using steel slag and modified steel slag as substrates
Authors: Yun Yupan , Zhou Xiaoqin , Li Zifu , Uddin Sayed Mohammad Nazim , Bai Xiaofeng
Published: April 2015

This research mainly focused on the phosphorus removal performance of pilot-scale vertical flow constructed wetlands with steel slag (SS) and modified steel slag (MSS). First, bench-scale experiments were conducted to evaluate the phosphorus adsorption capacity. Results showed that the Langmuir model could better describe the adsorption characteristics of the two materials; the maximum adsorption of MSS reached 12.7 mg/g, increasing by 34% compared to SS (9.5 mg/g). Moreover, pilot-scale constructed wetlands with SS and MSS were set up outdoors. Then, the influence of hydraulic retention time (HRT) and phosphorus concentration in phosphorus removal for two wetlands were investigated. Results revealed that better performance of the two systems could be achieved with an HRT of 2 d and phosphorus concentration in the range of 3–4.5 mg/L; the system with MSS had a better removal efficiency than the one with SS in the same control operation. Finally, the study implied that MSS could be used as a promising substrate for wetlands to treat wastewater with a high phosphorus concentration. However, considering energy consumption, SS could be regarded as a better alternative for substrate when treating sewage with a low phosphorus concentration.
Characteristics and indications of hydrogen and oxygen isotopes distribution in lake ice body
Authors: Zhen Zhi-Lei , Li Chang-You , Zhang Sheng , Li Wen-Bao , Shi Xiao-Hong , Sun Biao
Published: April 2015

Stable isotopes have been used to identify the characteristics of precipitation, evaporation, basin hydrology, and residence times. However, lakes in the cold regions are usually covered by ice for 5–6 months. To get a better understanding of stable isotopes characteristics and indications in lake ice bodies, ice and water were sampled during the icebound season in both the ice and water bodies in Dali Lake, and deuterium, oxygen-18 total nitrogen (TN), and the major ions were analyzed. The results showed that deuterium and oxygen-18 compositions (δD-δ18O) compositions in the ice body were greater than in the water body beneath, scattered on a straight line, and deviating downward from the global meteoric water line in the top right. The ice profile showed that the δD-δ18O compositions increased from the ice surface downward and decreased near to the bottom. In contrast, the TN and the major ions in the ice decreased from the ice surface downward and increased near to the bottom, meaning that the concentrations of δ18O had a negative correlation with the concentrations of TN and major ions. These indicated that stable isotopes can be used for tracing the nutriment and ion transport processes in the ice body.