bluuebunny/crossref_metadata_2025 huggingface dataset:
Iron Sulfide Inhibition: Field Application of an Innovative Polymeric Chemical
Authors: Wylde Jonathan J. , Okocha Cyril , Bluth Matthew , Savin Adam , Adamson Ben
Published: April 2015

Iron sulfide scale is prevalent in the industry and its chemical prevention is an area of recent focus by several research groups. There are very few examples where true inhibitor chemistry has been effective at controlling the scale, rather stoichiometric amounts of chelating agents are required. Partial inhibition has been achieved using classic scale inhibitor species such as phosphonates or maleic acid or sulfonated copolymers. Efficacy of these classic inhibitors against sulfide scale is poor and often uneconomically high concentrations are required.

This paper summarizes the work performed to deliver to the industry a true, high-performance sulfide scale inhibitor. This chemistry offers a true step-change in performance from existing technologies. An industry best-in-class rapid screening technique was used to systematically evaluate all current technologies in the market place and from this develop a detailed understanding on the structure-performance relationships of functional groups. By ranking the correlations, a range of novel polymeric chemistries were synthesized which provided significantly superior inhibition. Test methods are presented that mimic formation of these scales in the field and order of magnitude increases in performance over standard species are reported, thus representing a true step-change in the efficacy of sulfide scale inhibition.

The paper is largely dedicated to a field trial of this novel chemistry in USA. A severe iron sulfide fouling issue was being experienced in the water handling system. Intense sampling was performed when trialing classic chemistries such as THPS and phosphonate scale inhibitors as well as the novel polymeric product. The results speak for themselves and show that threshold concentrations of the new chemistry controlled sulfide deposition whereas order of magnitude more of standard chemistries are required to achieve the same efficacy.
Method for Rapid Assessment of Additives to Prevent Asphaltene Precipitation at Reservoir Conditions
Authors: Ovalles Cesar , Rogel Estrella , Morazan Harris , Moir Michael E.
Published: April 2015

Asphaltenes are blamed for several operational issues throughout the petroleum value chain such as: reducing volumetric production of wells, plugging of valves, pumps, tubing and pipelines during lifting, production, transportation, and storage. During refining operations, asphaltenes can cause heat exchanger and oven fouling and contributing to catalyst poisoning by coke and metal depositions. There are several techniques that can be used to deal with asphaltene precipitation issues: a) control pressure or other operational variables such as oil comingling, b) periodical cleaning (either chemical or mechanical), and c) additive injection to prevent asphaltene precipitation. Specifically, current methods for additive evaluation are time-consuming, rely exclusively on measurements at room temperature and could be very costly if they are carried out at reservoir conditions. Thus, the need for a method for rapid assessment of additives to prevent asphaltene precipitation is necessary to maintain well production and maximize economic benefits.

A new analytical technique was developed for screening and selection of asphaltene dispersants at reservoir conditions (<200°C). It is based on the On-Column Filtration method (Rogel 2009 and Ovalles 2015) and can quantitatively measure asphaltene dispersion activity by determining the percentage of reduction of asphaltene content versus the case without additives. It allows performing mass balances, is fast (<50min), repeatable, has small human intervention and uses a small amount of sample. A nonylphenolformaldehide resin (MW = 1600 g/mol) and three commercial additives were tested using gravimetrically separated asphaltenes and a Mid-continent crude oil. Reductions in the asphaltene contents up to 56% were found for the former and 38% for the latter. The mechanism in which asphaltene inhibitors and dispersants interact with asphaltenes depends on the type of additive and asphaltene composition and concentration. Some mechanistic considerations on the action of additives to prevent asphaltene precipitation are presented.
Microbial and Formation Damage Assessment of Secondary Treated Sewage Effluent for a Low Permeability Carbonate Reservoir Water Injection
Authors: Osode Peter I. , Rizk Tony Y. , Al-Obied Marwa A. , Alutaibi Ahmed S. , Al-Khaldi Mohammed H.
Published: April 2015

Large-scale seawater injection in two high permeability carbonate reservoirs within a remote onshore field commenced with the onset of oil production in early 2000. Following a recent incremental development plan that included an underlying low permeability (2 millidarcies (md)) reservoir with high calcium content (37,000 mg/L) formation water, it became necessary to examine alternative options to the seawater to avoid calcium sulfate scaling and microbial fouling. Secondary treated sewage effluent (TSE) is abundant from nearby urban treatment plants and presents an attractive option for the high-risk divalent ion formation brine environment.

An initial feasibility study focused on geochemical and microbial compatibility to assess the benefits expected from substituting the use of costly desulfated water1. Formation damage risk evaluation was also considered critical in the low permeability reservoir development since a significantly high initial capital expenditure associated with an injection water processing facility would further erode the economic value of the project. Laboratory coreflood experiments and conventional bottle tests were therefore conducted in addition to software simulation to appraise the TSE formation fluid interaction and inorganic scale deposition tendency at in situ conditions. The microbial study looked at the potential impact of both the microbial contamination and the nutritional load of TSE injection on the reservoir.

The study confirmed that sampled TSE had a relatively low content of contaminants such as oxygen demanding substances (ODS), heavy metals and dissolved solids with minimal formation damage risk compared to both seawater and field produced water. It also revealed variations of total organic carbon (TOC) in TSE, which may enhance troublesome microbial activities and impact the various systems' operational stages2.

This paper discusses the laboratory experiments and simulation conducted to assess the impact of injection TSE on microbial growth, in situ scale deposition and the associated formation damage risk. It also provides an insight into the effluent quality threshold required for injection in a reservoir of high divalent-salt connate water.
Treatment of Produced Water Using Chelating Resins: Laboratory Case Study
Authors: Patil Anil , Nanda Jajati , Waikar Jyoti
Published: April 2015

The impetus for waste minimization and water recycling within the oil and gas industry comes from increasingly stringent environmental regulations and deteriorating water supplies. The most challenging part in terms of the design of a water recycling system is minimizing the capital and operating costs while meeting water quality requirements. A recent development in selective functionalization of ion exchange resins enhances the chances of developing an economically feasible process for the selective treatment of produced water.

A case study is presented wherein produced water containing high concentrations of calcium, magnesium (hardness), barium, strontium, iron (scale) and boron (crosslinking agent) was treated with three different chelating resins. Dynamic column studies were conducted on all three chelating resins and breakthrough curves were determined for different cations. It was observed that iminodiacetic acid based resin selectively decreases the hardness of water; sulphonic acid based resin decreases the concentration of iron, barium, and strontium; while N-methylglucamine based resin selectively adsorbed the boron.

Analysis of water was conducted using Inductively Coupled Plasma Spectroscopy (ICP) and Ion Chromatography (IC) instruments. The calcium and magnesium ions adsorbed on the column were eluted by allowing 1mol/L hydrochloric acid to pass through the column. Recycling of adsorption and elution was found to be satisfactory. Dynamic adsorption operations showed that adsorption had significant effect on selectivity of cations, and low flow rate enhanced said adsorption.

This case study could be helpful for designing selective adsorbents for removal of scale forming cations, hardness favoring cations, and boron from produced/waste water in an economically feasible process. This work will provide a basis for further evaluations of field applications of resin filters for oilfield produced waters.
How Extremely High-TDS Produced Water Compositions Affect Selection of Fracturing Fluid Additives
Authors: Li Leiming , Qu Qi , Sun Hong , Zhou Jia , Legemah Magnus
Published: April 2015

Oilfield produced water can often contain high levels of total dissolved solids (TDS) in addition to hydrocarbons, precipitates, and suspended particles. The dissolved solids mainly consist of sodium, calcium, and magnesium salts. The combination of the high salinity and hardness in produced water can be very detrimental to many types of fracturing fluids that are commonly formulated for fresh water. Therefore, the industry has sought fluid systems that can be formulated directly with high-TDS produced water and perform well at high temperature. Such fluid systems can also reduce produced water disposal cost and fresh water consumption. A group of fracturing fluids was successfully identified recently that performed very well at high temperatures when formulated with untreated, high-TDS produced water. The produced water tested had TDS up to about 330,000 mg/L and hardness (calcium carbonate equivalent) up to about 90,000 mg/L. The fracturing fluids comprised organometallic-crosslinked derivatized polysaccharides. In a typical test, the viscosity stayed above 100 cP (at 100/s shear rate) for over 80 minutes at 275 °F, recorded for a fracturing fluid prepared with untreated produced water with extremely high TDS and hardness. The magnitude and lifetime of the fluid viscosity were dependent on a number of factors such as the produced water composition, temperature, polymer loading, fluid pH, etc.

The success of the fracturing fluids formulated with untreated high-TDS produced water depended on the matching choice of additives to water compositions. In addition to the polymer (the derivatized polysaccharide polymer) and the organometallic crosslinker, a number of other fluid additives were used that worked synergistically in the untreated produced water. For example, one such additive (additive-A) was a derivatized alcohol. Adding the appropriate concentrations of the alcohol in the fluid formulas significantly mitigated the damage caused by the high hardness level in the produced water. Without this alcohol, the fluid viscosity could drop by well more than 50% under the same conditions. Another additive (additive-B) was a water-soluble salt. At right dosage, the salt could enhance the high-temperature stability of the fluids. In the meantime, the salt was also able to control crosslinking of the fracturing fluids, making it possible to greatly facilitate fluid placement.

The underlying working mechanisms of the high-temperature fracturing fluid additives selected for untreated extremely high-TDS and hard produced water will be discussed, and the field-related laboratory test results will be presented.
Selection of Calcium Carbonate Scale Critical Values for Deepwater Production
Authors: Zhang Ping , Allan Keith , Hugh Bourne
Published: April 2015

Calcium carbonate scale threats for deepwater developments have been predicted by calculating the saturation ratio (SR) and mass of calcium carbonate.

Assessing the threat scale may pose to an operation allows the design and implementation of robust barriers to reduce the risk. Scale threat assessment is particularly important in the early phase of a project when options for controlling the threat are being evaluated. It is important to correctly interpretate scale prediction result and its operational significance in terms of the threat likelihood and severity. Widely adopted guidelines, based on industry experience built up over many years from operations in US land and in the North Sea, have been used to aid interpretation. However, the relevance of these guidelines for deepwater projects has long been challenged.

The relationship between predicted SR and mass of calcium carbonate in deepwater is explored. Through case studies, it is apparent the current guidance is not stringent enough for deepwater. Additional guidance for deepwater operations is proposed.

This paper describes the deepwater operational experience that was used to justify a change in the critical SR and mass values in the scale threat assessment guidelines now adopted to assess the likelihood of scaling in deepwater fields.
Minimizing Surfactant Adsorption Using Polyelectrolyte Based Sacrificial Agent: a Way to Optimize Surfactant Performance in Unconventional Formations
Authors: He Kai , Yue Zhiwei , Fan Chunfang , Xu Liang
Published: April 2015

Surfactant is a critical component in fracturing fluid to help achieve higher productivity from unconventional oil and gas formations. However, adsorption of surfactant onto reservoir rocks and proppant could lead to inefficient use. The large surface area of shale formations (up to 700 m2/g) could yield a significant loss of surfactant attributed to adsorption onto reservoir rock. Field production data from the Barnett shale indicates that most surfactant could be tied up within the reservoir. For example, 3 gpt (3 gal/1,000 gal ~3000 ppm) of surfactant was injected into the reservoir, and only 0.5 gpt (or 500 ppm) was recovered when production began; surfactant concentration further decreased to 50 ppm in one month. Strong adsorption could potentially limit the contact of surfactant with reservoirs, as most surfactants could be adsorbed near-wellbore (NWB) before reaching the interior of the reservoir. Therefore, a need exists to reduce surfactant's adsorption to further optimize its performance during hydraulic fracturing.

This paper discusses static and dynamic adsorption tests performed to evaluate the use of polyelectrolytes (PETs) to reduce surfactant adsorption onto the Rainbow shales in Canada. Dynamic surface tension measurements and UV-vis data indicated surfactant adsorption could be significantly reduced using PETs based on the competing mechanisms. Additionally, oil recovery laboratory results reveal that surfactants extract more oil in the presence of PETs. On the other hand, scale inhibition performance testing suggests that these PETs can also serve as scale inhibitors. In this study, the inhibition efficiency of the PETs is compared to commonly used phosphonate and polymeric scale inhibitors. Static bottle testing results indicate the PETs can effectively control calcium carbonate scale formation. The synergistic effect between surfactants and PETs suggests a new route for formulating multifunctional surfactant blends that can be tailored to specific formation rocks.
A New Environmentally Friendly Acidizing Fluid for HP/HT Matrix Acidizing Treatments with Enhanced Product Solubility
Authors: Rabie Ahmed I. , Saber Mohamed R. , Nasr El-Din Hisham A.
Published: April 2015

The success of matrix acidizing treatments, whether in carbonate or sandstone formations, depends significantly on the selected acid or acid mixtures. Limitations are applied on all existing acidizing fluids including hydrochloric acid and organic acids. These limitations include: low dissolving power, product solubility, stability, biodegradability, and the inevitable cost of additives necessary to mitigate corrosion problems. This work proposes a new mixture of lactic and gluconic acids which offers favorable technical characteristics and excellent health and environmental profile. After formulated, the acid was tested and optimized for the maximum calcium product solubility. The new acid is noncorrosive, nonvolatile, nontoxic, and can be used at a higher pH with significant sequestering power, and it is readily biodegradable (98 % at 48 h). The solubility of calcium salt of this acid is approximately 400g/l (compared with 300 g/l for calcium acetate, 166 g/l for calcium formate, and 79 g/l for calcium lactate). Interestingly, sodium salt of the acid mixture was reported as a corrosion inhibitor for steel alloys.

The objectives of the work are to: (1) examine the dissolving capacity and reactivity of the proposed acid through solubility and reaction rate studies over a temperature range of 80-300°F using the rotating disk reactor, (2) investigate the effectiveness of the new acid to create dominant wormholes and determine the optimum injection conditions in calcite cores.

Acid capacity reactions with Pink Desert limestone powder showed that 1:1 of 1 M lactic:gluconic acid mixtures was the optimum molar ratio that resulted in dissolving the maximum calcium amount for the reaction at 25°C and 500 rpm, while the reaction of lactic acid alone at the same acid concentration showed a white precipitation of calcium lactate in the collected samples. Reaction rate experiments on the rotating disk reactor showed that the rate of reaction of the proposed acid at 1:1 molar ratio is confined by the reaction rate of the two individual acids (lactic and gluconic acids). However, the reaction of lactic acids resulted in white precipitates on the surface of the rock disks used in the experiments. Coreflood study showed the ability of the new acid mixture to stimulate Indiana limestone cores at various injection rates, acid concentrations, and over temperature range between 150 and 300°F. The results also confirmed that 1:1 molar ratio of the two acids is the optimum for the minimum acid pore volume required to breakthrough. 20 wt% of the proposed acid was the optimum acid concentration associated with the minimum acid pore volume. Above this concentration, little impact was noted and the reduction in the pore volume leveled off.
Diblock Copolymers: A New Class of Fluid Loss Control Additive for Oilfield Cementing
Authors: Cadix A. , Wilson J. , Barthet C. , Phan C. , Poix C. , Dupuis P. , Harrisson S.
Published: April 2015

Oil well cementing uses a variety of organic additives such as dispersing agents, retarders or fluid loss control additives. The later, which prevent interstitial water from filtering into the formation during cement placement, are generally polymer based. A widely used class of fluid loss control additive are the high molecular weight Sulfonated copolymers, generally comprising AMPS (2-Acrylamido-2-methylpropane sulfonic acid) copolymerized with Acrylamide (Am) or N, N′ Dimethylacrylamide (DMA). The mechanism of action of these polymers has been studied recently and it was demonstrated that adsorption onto the cement surface is crucial to achieve the required product performance. It was also shown that other solutes and admixtures present in the cement interstitial solution can hinder adsorption resulting in performance losses. Thus it has been recommended to incorporate an additional monomer containing strongly adsorbing units in the copolymer to enhance the interaction with the cement surfaces hence limiting competitive adsorption issues.

In this study we investigated the use of diblock copolymers comprising a short but strongly adsorbing block and a long second block of DMA-AMPS as a potential new class of filtration control agent. We showed that diblock copolymers with much lower molecular weights than statistical polymers can provide satisfactory fluid loss control performance. Furthermore, it was demonstrated that these structured polymers show good formulation flexibility and deliver more robust performance in the presence of a wide range of admixtures and solutes.

Finally we focused on the analysis of the adsorption on cement of various formulation admixtures and how it affected the adsorption of our diblock copolymers. With the aid of an analytical method utilising size exclusion chromatography of collected filtrate from HPHT filtration cells, it was possible to have a direct access to a fluid loss polymer concentration in the filtrate even in the case of complex formulations.

Based on these studies, the mechanism of action of the diblock copolymers as fluid loss control agents is discussed with reference to that evoked for statistical polymers.
Scale Modeling in Reservoirs: a New Simulation Capability and its Validation with Field Data
Authors: Chen Huey J. , Shi Wei
Published: April 2015

The development of oil and gas reservoirs in the deep water environment is playing an increasingly significant role in supporting the global energy demand. Oil field scale is an important aspect of flow assurance that determines continuous production from reservoirs, because improper scale management could result in astronomical losses. Currently most commercial software packages for scale prediction and risk assessment use stand-alone thermodynamic models that rely on water composition data as input parameters. As seawater injection has become an integral part of deepwater development, the coupling of scale modeling with reservoir simulation becomes necessary to not only track scale reactions and precipitation in the reservoir, but also to assess scaling risks in production wells and surface facilities as a result of the these reactions. Appropriate treatment strategies can thus be recommended based upon simulation results. The scale reaction for barium sulfate (BaSO4) has currently been implemented as a coupled option in our in-house reservoir simulator, CHEARS. Besides conventional reservoir simulation results, the model also outputs scale related information, such as barium and sulfate scaling ion concentrations, the amount of barium sulfate precipitation, scaling tendency of barium sulfate, as well as the time and extent of injection water breakthrough over years.

The scale model in reservoir simulation has been validated using both literature data (Delshad and Pope, 2003) and field data from one of Chevron's assets. The recommendations for scale control based upon the simulation results are in good agreement with field operation. Scale modeling in reservoir is expected to provide a more precise evaluation of scaling risks under challenging production conditions, and a more realistic recommendation for scale squeeze treatment. With the continuous advancement in deepwater development, scale modeling in reservoirs should be an integral part of reservoir management. Reservoir management strategies will be implemented in the field development with the collaboration among experts from different disciplines such as reservoir, scale, flow assurance, production, and process engineers.
Zeta Potential Measurements: Impact of Salinity on Sandstone Minerals
Authors: Shehata Ahmed M. , Nasr-El-Din Hisham A.
Published: April 2015

Waterflooding has been used for decades as a secondary oil recovery mode to support oil reservoir pressure and drive oil into producing wells. Recently, extensive experimental work has indicated that optimizing the salinity of the injected water is an enhanced oil recovery technique that improves oil recovery in sandstone and carbonate reservoirs. Ion interactions between formation water, crude oil, injection water, and rock surface are quite complex. The question is how the surface charge of the minerals of sandstone formation affects the waterflooding performance. In this study the zeta potential measurements are conducted for rock/brine interfaces using the Phase Analysis Light Scattering (PALS) technique.

This work demonstrates the results of zeta potential experiments to evaluate the effect of electrical surface charge and double layer expansion for common sandstone minerals. Four sandstone rock types (Buff Berea, Grey Berea, Parker, and Bandera) with different clay contents are studied. In addition, several minerals such as quartz, carbonate (calcite and dolomite), clays (kaolinite, chlorite, and montmorillonite), micas (muscovite, biotite, and illite), feldspars (microcline and anorthoclase), and ilmenite are selected to perform this work. Various brines are tested including seawater, 20% diluted-seawater, 0.5 wt% NaCl, 0.5 wt% MgCl2, and 0.5 wt% CaCl2.

Based on the results of 100 experiments we found that the monovalent cations are more efficient in increasing the absolute values of the zeta potential than the divalent cations at 25°C. Zeta potential becomes more negative while the salinity of the brine decreased. Changing the pH of the solution causes a significant alteration in charge of Buff Berea and Bandera sandstone particles and subsequently, the zeta potential values. The zeta potential of Bandera is more negative than that of Buff Berea at any condition of pH in the range of 5 and 10. It is observed from the results that most of the minerals tends to be more stable for 0.5 wt% NaCl solutions compared to 0.5 wt% CaCl2 and 0.5 wt% MgCl2 solutions. Feldspars surfaces charge are significantly influenced using 0.5 wt% NaCl, followed by micas and clays. The resulting zeta potentials for the dolomite and calcite minerals showed different trend from the other sandstone minerals for low-salinity brine. For dolomite, all the samples show positive zeta potentials at original pH. At low pH, dolomite shows small negative zeta potentials in 0.5 wt% NaCl.
Mechanisms of Environmentally Acceptable Inhibitors for Zinc Sulphide Inhibition
Authors: Williams H , Tortolano C , Champion Nalco , Adenuga T
Published: April 2015

Carbonate and sulphate scales are the most common types of mineral deposit associated with the recovery and processing of hydrocarbon and associated produced water. In high temperature fields (>140°C) within the North Sea, more unusual scale types have been observed, namely zinc and lead sulphide. Limited studies have been focussed on zinc sulphide (ZnS), and mechanisms for scale inhibitors to control this scale are still relatively unknown.

In laboratory studies, the relatively small amount of ZnS deposited and ‘soft’ scale characteristics make it difficult to test ZnS using traditional test methods, especially at high temperature. A novel dynamic loop test combining the traditional test coil and novel test filter system has been developed to evaluate ZnS inhibitors and was published in SPE paper 169810.

The mechanisms of the inhibitor interactions with ZnS suggested from this previous study have been further evaluated and will be reported in this paper. The investigation of the inhibitor mechanisms have been addressed by scanning electron microscope evaluation of scale texture and size distribution of scales recovered from static bottle tests conducted at 70°C.

Several different generic types of ZnS scale inhibitor chemistries were selected based on the previously published study. Type 1 inhibitor is dispersion/nucleation inhibitor, Type 2 is nucleation/growth inhibitor, and Type 3 has no inhibition function on ZnS. The test results at 70°C agree well with the mechanism suggested in the previously published tube / filter blocking study, and the inhibition mechanisms are reinforced. The difference in particle size, particle quantity and crystal morphology shows how different generic types of inhibitors interact with the ZnS scale.

This paper is a comprehensive study of the mechanism of ZnS formation and inhibition via a range of experimental test methods to fully understand the impact that inhibitor functional groups have on crystal growth inhibition, nucleation inhibition and dispersion mechanism.
Stimulation of High Temperature SAGD Producer Wells Using a Novel Chelating Agent (GLDA) and Subsequent Geochemical Modeling Using PHREEQC
Authors: Ameur Z. Ouled , Kudrashou V.Y. , Nasr-El-Din H.A. , Forsyth J.P.J. , Mahoney J.J. , Daigle B.J.
Published: April 2015

Acidizing of sour, heavy oil, weakly consolidated sandstone formations under steam injection is a real challenge. Fines migration, sand production, inorganic scale, corrosion products, and damage due to asphaltene precipitation are some of the common concerns with these sandstone formations. They cause decline in the productivity of the wells, and there is always need to stimulate these wells to restore their productivity. Furthermore, the complexities of sandstone formations require a mixture of acids and several additives, especially at temperatures up to 360°F. Three treatments were tried in a horizontal well in this field: HCl acid, A (GLDA), and B chelating agents. In this paper, we evaluate the results of field applications using geochemical modelling, production data, and analysis of well flow back fluids after field treatments.

The field treatment included pumping a foaming agent to have proper rheological characteristics and a better controlled pumping process, followed by the main stage of the treatments. The treatment fluids were displaced into the formation by pumping produced water and were allowed to soak for 6 hours, then the well was put on production, and samples of flowback fluids were collected. The concentrations of key cations were determined using ICP, and the chelate concentration of the chelating agent A was measured utilizing a titration method using ferric chloride solution. Geochemical modelling was conducted using specialized software, and was used to predict the concentrations of key ions in the flow back samples.

The first two treatments including HCl acid and chelating agent B produced results below expectation. The third treatment using GLDA was successful and the well productivity increased significantly. The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without adversely impacting the water cut, causing sand production, or fines migration. Analysis of flow back samples indicated that iron was the main cation, which shows that the chelate dissolved corrosion products. Geochemical modelling was able to predict the trend noted in the concentrations of key ions and chelant in the produced fluids.
Targeting High Molecular Weight Wax
Authors: Wei Fang , Acosta Erick , Gawas Kiran , Krishnamurthy Pushkala
Published: April 2015

Wax deposition is one of the major problems for onshore and offshore crude oil production. High molecular weight wax (HMWW) is commonly defined as a wax containing more than 40 carbons in its chemical structure. These types of wax are challenging to treat, as they form hard deposits that can be difficult to remove. Most paraffin inhibitors available in the market currently are not effective at inhibiting the formation and deposition of HMWW in oil production systems. This paper discusses extensive work on understanding HMWW characteristics and chemical methods to treat such deposits. A variety of wax characterization techniques, such as cold finger (CF), differential scanning calorimetry (DSC), cross polarized microscopy (CPM), and high-temperature gas chromatography (HTGC), were used to study the impact of inhibitor chemistry on wax characteristics.

Oil from South Texas with high wax content (8%) was evaluated using five different types of inhibitor chemistry. DSC and CPM were used to obtain the wax appearance temperature (WAT), and CF was used to deposit the HMWW and evaluate inhibition efficiency. HTGC results were obtained from the wax collected from CF to determine carbon distribution of the deposit. DSC of the wax was also performed to obtain the crystallization of the wax and estimate the wax content in the deposit.

Of the five chemistries evaluated, one showed good performance, with approximately 30% inhibition, while two polymers reduced the crystallization temperature and softened the wax deposit. The other two chemicals did not show any effects on the HMWW.
Effect of Environmental Parameters on the Stability and Performance of Oil and Gas Biocides
Authors: Williams Terry M. , Schultz Christine M.
Published: April 2015

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.
Study on Abnormal Viscosity Development in High-TDS Produced Water
Authors: Sun Hong , Li Leiming , Mayor John , Carman Paul
Published: April 2015

With limited availability of fresh water, more and more stimulation operations turn to produced water. In such operations, polymers must sufficiently hydrate first to enable effective crosslinking and ensure proppant transportation and placement. On the other hand, produced water from unconventional formations (such as Marcellus and Bakken shales) is famous for its high total dissolved solids (TDS) and high divalent cation content. Produced water contents change from time to time, and from location to location, posing a tremendous challenge in stabilizing the performance of the fracturing fluids prepared in such water. Predictable performance of fracturing fluids made with unpredictable produced water is highly desirable in order to utilize produced water.

This paper will present studies of hydration behavior of non-charged polysaccharides, such as, guar, HPG (hydroxypropyl guar) and HEC (hydroxyethyl cellulose), in water with controlled salinity and multivalent cation concentration, including Ca2+, Mg2+, Fe3+, etc., under various temperatures. The results are surprisingly more complicated than most may assume. For example, higher salinity may suppress linear gel viscosity, while multivalent cations do exactly the opposite. Contrary to the common knowledge that viscosity generally decreases with elevated temperatures, in some temperature ranges, an opposite trend is observed instead; and over a wider temperature range, a U-shaped trend is observed. Such counter-intuitional results will be presented and the mechanism will be explored to explain such observations. Semi-empirical equations will be proposed to predict the viscosity response of polymers in real-world produced water. Results generated in laboratory synthetic high-TDS water are then compared to those obtained in field produced water to validate the study. With systematic studies, optimized formulas of fracturing fluids based on various produced water samples have been found for stimulation operations for unconventional formations and conventional formations as well.

This paper will provide in-depth understanding of effects of a number of produced water ingredients on the performance of the fracturing fluids prepared with produced water, with emphases in areas such as polymer hydration, crosslinking, and high-temperature stability.
Magnetic Nanoparticles for Efficient Removal of Oilfield “Contaminants”: Modeling of Magnetic Separation and Validation
Authors: Prigiobbe Valentina , Ko Saebom , Wang Qing , Huh Chun , Bryant Steven L. , Bennetzen Martin V.
Published: April 2015

In this work, we present the study of an efficient method of separating “contaminants” from water produced from oil reservoirs, using magnetic nanoparticles (MNPs). Micron-scale, highly stable oil droplets as well as divalent cations such as Ca2+ can be removed from the produced water through the adsorption onto functionalized MNPs. The method employs MNPs to initially attach to the oil droplets or to the cations, and then to separate them from the liquid phase using a magnetic field. After separating out the “contaminant”-free water, the MNPs can be regenerated and re-used. As the collection of the contaminant-attached MNPs by the application of magnetic field gradient is a critical step for the process, we developed a 1D mathematical model for the description of the dynamics of the MNP collection in the framework of the sedimentation theory. The conservation equation for MNPs is coupled with the flux function, which accounts for not only gravity force but also magnetic force and Brownian interaction. The model describes both the behavior of colloidal particles during settling and the enhancing effects of the magnetic field due to attraction of MNPs towards a magnet. Simulations were compared with measurements from settling tests of a suspension of MNPs.
New Hydrogen Sulfide Scavenger Development for Downhole Mixed Production Applications - Lab and Field Data
Authors: Lehrer S. , Jovancicevic V. , Braman S.C. , Soos L. , Macleod J. , Kurrasch Jason
Published: April 2015

Production of sour crude oil releases hydrogen sulfide (H2S) into production tubing and surface equipment, causing corrosion, flow assurance issues, safety, and environmental concerns for the producer. As a result, increased costs related to metallurgical upgrades, gas sweetening equipment, increased manpower costs for monitoring, and liability from the potential release of H2S can become significant parts of the total operation cost. These issues can be alleviated if the H2S is reliably removed downhole and prevented from reaching the surface.

Conventional hydrogen H2S scavengers such as triazines or glyoxal are commonly applied by direct injection topside to mitigate H2S in oil and gas production facilities. However, when applied in direct-injection applications, these scavengers exhibit slow kinetics that reduce their effectiveness in short residence-time systems, resulting in a much greater amount required than theoretical efficiency would predict. Neither triazines nor glyoxal are suitable for downhole application because of their low thermal stability and, in the case of triazine, its high scaling tendency.

To achieve reliable and cost-effective removal of H2S topside or downhole, the development of a new scavenger and a new delivery system for downhole application was required. As a result, a new non-triazine, organic acid metal complex-based H2S scavenger (OAC) with high-temperature stability, fast kinetics and quantitative H2S removal was developed. The new delivery equipment comprises an injection skid, H2S monitoring equipment, and an automated chemical dosing system to ensure delivery of the precise dosage required to remove H2S downhole.

Field test results for the new OAC scavenger and delivery system will be presented for mixed production applications, demonstrating the ability of this approach to reliably remove H2S both topside and downhole.
An Alternative to the Capillary Suction Time Test
Authors: Sethi Richa , Hinkel Jerald J. , Mackay Bruce
Published: April 2015

The oil and gas industry has adopted several methods to obtain insight as to how a fluid may affect reservoir material. The Capillary Suction Time (CST) test has become a de facto standard test method, largely due to its simplicity and speed. The most obvious shortcoming of the CST test is that it introduces a medium (paper) that is far different from anything found in an actual reservoir; in fact, one may argue that the CST test is essentially a measure of the interaction of the test fluid with the paper. The lack of theoretical foundation of the CST test precludes reproduceable results or proper estimation of errors in measurement. We present a new test method that observes only intrinsic properties of the formation in contact with a test fluid, bolstered by a strong theoretical basis, in stark contrast to the CST test.

Our method preserves the desirable attributes of the CST test, but replaces imbibition into paper with imbibition into reservoir material. The method uses a comminuted sample, and the results from the imbibition step are used to determine formation wettability in the form of the advancing contact angle. The results from a subsequent drainage test are used to determine the receding contact angle, and the capillary pressure versus saturation curve.

Prior to performing the drainage test, test fluid is placed on top of the saturated pack and the permeability of the pack to the test fluid is determined. The permeability of the pack to liquid is then compared to the pretest permeability of the pack determined using nitrogen. Use of this pack as a testing environment allows the technique to be applied to formation samples of virtually any permeability and porosity.

We have found that there is no correlation between CST test data and the permeability data obtained using the new method presented here. We present several cases in which a positive result from a CST test is inconsistent with the results obtained from the new test method. We maintain that the discrepancies cast serious doubts on the general applicability of the CST test as a tool for studying rock/fluid interactions.

In summary, there is a great need to standardize testing that investigates rock/fluid interactions. The widely used CST method introduces a foreign material and it does not offer sufficient resolution, reproducibility, or estimation of error. Even if the CST method were adequate, the lack of standardization in testing and analysis methodologies makes comparisons of published results difficult.

Our method provides superior results. The strong theoretical foundation of the new method allows rigorous analysis making comparisons between treating fluid options far more trustworthy.
The Evaluation of Polycationic, Carbohydrate-Based Surfactants as Viscoelastic (VES) Fracturing Fluids
Authors: Whitlock Laura , Sanders Aaron , Knox Paul
Published: April 2015

Hydraulic fracturing plays an important role in maximizing the recovery of oil and gas in North America. Viscoelastic surfactant based fluids (VES) are an important class of fracturing fluids (Ghaithan, 2014). They are reputed to cause less formation damage during the fracturing process and break cleaner, leaving less material in the formation to impede the flow of hydrocarbons (Brown, 1996). Cationic surfactants are typically used for this application, but do not exhibit good tolerance to or solubility in the salts used to inhibit clay swelling. They are also not particularly biodegradable and have an unfavorable toxicity profile. Cationic surfactants with an improved ecotoxicity profile as well as improved tolerance to salts are needed. Improved temperature tolerance is also desired, in order to apply to a wider range of well types.

Carbohydrates have the ability to react with a variety of substances and can be conveniently cross-linked to form polycationic materials. As such, molecules can be created that mimic the polymer backbones used in fracturing fluids today, potentially eliminating some of the negative side effects of those same polymers. Carbohydrate-based, polycationic molecules are created from bio-renewable resources such as sucrose and vegetable oils. The incorporation of ether links and short-chain components within these molecules imply a better biodegradation profile and lower toxicity than traditional long-chain cationics.

Several new polycationic, carbohydrate molecules were synthesized in the lab in order to demonstrate the flexibility and range of the chemistry and explore structure-activity relationships. When formulated into viscoelastic fluids, smaller polycationics demonstrated excellent tolerance to salts, at times requiring the presence of salts in order to show viscoelasticity with enough viscosity to suspend proppant. In addition, as the number of crosslinkers per molecule increased, the resultant formulated viscosity increased, however the tolerance to salt decreased.
Determination of the Diffusion Coefficient of Methanesulfonic Acid Solutions with Calcite Using the Rotating Disk Apparatus
Authors: Reyath Sajjaat Muhemmed , Nasr-El-Din Hisham A. , Rimassa Shawn
Published: April 2015

Methanesulfonic acid (MSA) has been proven as a scale remover and, more recently, as a stand-alone stimulation fluid in carbonate acidizing. MSA is a strong alkyl sulfonic acid having a pK value of -1.9, and it dissolves carbonate and oxides with its calcium water-soluble salts. Although the acid has many promising results for acidizing, little is known in relation to its detailed kinetics. This study aims to understand the reaction profile of MSA to provide relevant information to scientists and engineers to design acidizing jobs with this improved fluid.

The dissolution of calcite in MSA was studied with the aid of a rotating disk system at 1000 psig in the temperature range 73-250°F. As a result of this study dissolution rate parameters for this system are reported for the first time. Details of the approach for this study include using marble disks of 1.5-in. diameter and 0.7-in. thickness. The dissolution rate was found by measuring the calcium concentration in the effluent as a function of time using inductively coupled plasma (ICP). The effects of MSA concentrations (5 to 20 wt%), disk rotational speeds (100 to 1500 rpm), and temperatures on the rate of dissolution were also investigated.

Experimental results showed that, within the range of temperatures tested, the dissolution rate of MSA with calcite was mass-transfer limited even at high disk rotation speeds. The diffusion coefficient of a 5 wt% MSA fluid at 150°F was found to be 5.29 × 10−5 cm2/s and at 250°F diffusion coefficient was found to be 3.03 × 10−4 cm2/s. The acid diffusivity increased with increasing system temperature.

Determination of the dissolution rate of MSA will increase the understanding of its performance as a stand-alone stimulation fluid. Its high acidity, high solubility of its calcium salts, and good thermal stability, along with its low corrosivity and readily biodegradable composition makes this acid an attractive alternative to HC1 in designing high temperature acidizing applications.