Formation of scales in near-wellbore reservoir/downhole and production systems can lead to production loss, system integrity and reliability degradation, and fouling of device and equipment. The mitigation and remediation of oilfield depositions can be difficult and costly. Better understanding of the key factors impacting scale dissolution, such as temperature and pH will benefit scale mitigation practices. Most of the research and investigation of silicate dissolution for example are based on low temperature experiences (e.g., <100 °C). Strong acids such as concentrated HCl, HF and aqua regia may not be applicable for field application. In this study, field depositions with various scale types such as silicates, carbonate, sulfides are characterized and used for studying effects of pH, temperature and solvent on their dissolution. Experiments with oilfield scale deposit samples including silicates were conducted with high temperature thermal aging cells at temperature range >100 °C and pH from 6 – 8. Dissolution test with field scale samples were also conducted under ambient conditions. Various solvents including xylene, HCl and acetic acid were used in the test. To summarize the results, decreasing temperature has limited effect on dissolution of magnesium silicates, but improves dissolution of calcite and anhydrite which coexist with the field sample. Decreasing pH improves the dissolution of magnesium silicate and calcite. Total amount of dissolved silicates can increase significantly due to appropriate pH decrease. Solution pH is increased dramatically due to the formation of hydroxyl ions during the dissolution process. The reaction for dissolution of metal silicate scale is proposed based on observation and results in the study. More fine particles are produced after dissolution and suspended in solution for at least 15 minutes, which makes solid mitigation possible by applying proper agitation. Oilfield deposits can include a variety of components, and appropriate scale sample characterization should be utilized for selection of mitigation/remediation approaches. This paper provides novel information of oilfield scale dissolution (including silicate scale) at high temperature by using field applicable treatment approaches. Results lead to better understanding of silicate dissolution at various pHs and temperatures, and required conditions for successful mitigation and remediation of oilfield scale deposits

Production from highly paraffinic crude oil wells poses unique technical challenges such as poor flowability and paraffin deposition on the production tubing. Paraffin deposition increases the lift load on the pump, reduces pump efficiency, and eventually plugs the pump. To restore the productivity of these wells a common solution is to inject hot oil or hot water at 160°F–200°F to clean the deposits. This process imposes higher operating cost and lost production due to well downtime. Paraffin inhibitor (PI) and pour point depressant (PPD) have been used to treat paraffinic fluids but are not effective for wells with high water cuts. These wells when treated with PI/PPD still require high cost maintenance such as the hot oil/water jobs and/or well workover. This paper presents a more effective treatment using tailored chemical mixtures to form a water dispersion with the paraffinic oil, thus to increase oil flowability and reduce deposition. A novel test method has been developed to evaluate effectiveness of treatment chemicals on various paraffinic oils based on flowability and cleanliness. The test method has been validated with field trial data from three different wells in the Uinta Basin, Utah and Julesburg Basin, Colorado. The results of the field trials showed a significant increase in pumping efficiency and crude oil production. Need for hot water application was also reduced or eliminated for the treated wells. Improved oil and produced water quality were also observed. These results demonstrated that the water dispersion-based treatment is a more effective treatment for high paraffin wells with high water cuts.

Asphaltene deposition and plugging of pipelines during oil production and transportation is considered a challenging flow assurance issue. Instead of adding dispersants, the concept proposes to remove asphaltenes from the flow stream by means of electro–deposition prior to transportation to prevent later deposition. This study mainly examined the effect of molecular composition on the efficiency of electro-deposition. Two sources of asphaltene, namely asphaltenes from coal tar ("AS-C") and asphaltenes from bitumen ("AS-B") with different molecular composition were collected in this study. Elemental analysis revealed that both AS-B and AS-C possessed transition metals (V and Ni) and heteroatoms (O, N and S). The effect of oil components on the stability of two asphaltenes was studied. After conducting the electro–deposition of both asphaltenes with various oil components and electric field strength, the deposition charge and recover rate was recorded and compared. During stability test, the amount of precipitated AS-B decreased with increasing aromaticity of solvent, while that of AS-C was constant. For electro–deposition, the electro–kinetic behavior of AS-C reveals strong sensitivity to the oil components. Interestingly, both asphaltenes exhibited a change in the net charge, which occurred under 6000 V/cm and 12000 V/cm for AS-B and AS-C respectively, as evidenced by a change in the electrode upon which deposition ocurred. Based on the results, the efficiency of electro–deposition is confirmed to depend upon the metal and heteroatoms of asphaltenes; in addition, and by interaction with these elements, the oil composition and electric field affected the stability, net charge, and electro–kinetic behavior of apshaltene. However, our study is the first to show that the current density plays a role in the net charge of the asphaltene molecule and offers an explanation to the controversy over the polarity or the charge sign of asphaltenes, which gives a clue to understanding the microstructure of asphaltenes. In addition, this is the first study to include the effect of oil components and electric field strength on the performance of deposition, which makes further optimization of the proposed process possible.

Recent studies revealed that solids from lab-generated deposits often exhibit compositional differences from those of field deposits, pointing to a more complex fouling process in field operations. The objective of this work was to understand and apply knowledge from field deposit characteristics in order to design and conduct laboratory experiments which yield solid deposits with comparable compositional fingerprints. This approach allows a more objective and reliable product development and recommendation strategy to be adopted for increased success in the field applications. First, oil and deposit samples from an offshore field was characterized. Second, samples of the asphaltenes extracted from oil (AEO) and from the deposit (AED) were characterized based on solubility using an Accelerated Solubility Test (AST). A customized Asphaltene Dynamic Deposition Loop (ADDL) was used in this study to simulate the precipitation and deposition of asphaltenes from the crude oil. Crude oil used in the tests was from the same well where the deposits were collected. ADDL tests were conducted at high temperature and pressure and the composition of the collected deposit from this test was compared with the deposits from the field. At last, Light Scattering Technique (LST) was applied to screen asphaltene inhibitors (AI). Four candidate chemistries were tested on LST. To confirm the efficiency, the high performer was tested on ADDL under dynamic conditions. Deposits collected from the ADDL were characterized and results showed a high degree of similarity to the field deposit. AI1 was evaluated by ADDL and it decreased the deposition in the filters by 60% and 84% at 1000 ppm. This product was selected to be tested in the field and a plant trial is ongoing.

Iron sulfide scaling is a severe problem in flow assurance and asset integrity in oil and gas and deep-water production. FeS scale control is challenging due to the extremely low solubility, fast precipitation kinetics and complexity of ferrous iron and sulfide chemistry. Despite the ubiquity of FeS, we have limited understanding about the kinetics and thermodynamics of iron sulfide. To address this problem, we have developed a reliable anoxic plug flow reactor using argon gas to remove oxygen and PIPEs or MES buffer to control pH. The FeS (mackinawite) solubility, precipitation kinetics and phase transformation were the focus of this study. The impact of temperature (25 – 90°C), pH (5.92 – 6.91), ionic strength (0.15 – 4.30 M), Fe(II) to S(-II) ratio, dispersant and chelating reagent have been investigated. It was found that mackinawite is always the first FeS precipitated and could be stable for a week. It was suggested that low pH, high temperature and low ionic strength could accelerate the FeS phase transformation. FeS precipitation is under diffusion control at pH lower than 6.1, which could be accelerated by high temperature and high ionic strength. But the precipitation kinetics would be faster at higher pH. Some evidence suggests the importance of neutral FeS(aq) species at pH 6 −7. A polymeric compound containing amide functional group showed a promising effect by controlling the FeS particle size and reducing FeS scale retention rate. EDTA showed satisfactory FeS scale inhibition effect, as well as reducing FeS scale retention and H 2 S corrosion rate.

Inorganic scale control of sulphate and carbonate scales with polymer, phosphonate and phosphate ester scale inhibitors is well established within the oilfield service industry. The environments in which these chemical work best have been published such as vinyl sulphonates are known to be very effective for sulphate scale control in low temperatures whereas phosphonates are much less effective under these same conditions but improve at higher temperatures. What is less well understood is the potential for synergistic interaction with blends of polymers/phosphonates/phosphate esters to give reduced treatment rates, lower chemical discharge volumes and potentially lower treatment cost. In this paper evaluation of two North Sea produced waters will be outlined. Both produced brines have a high barium sulphate scale tendency but differ in the temperature at which the fluids arrive and depart the topside process one case with a temperature of 20C and the other at 90C. Static bottle test data will be presented to evaluate the crystal growth performance of single scale inhibitors and the improvements observed when blends of these same inhibitors are applied. Select dynamic tube blocking tests data to evaluate nucleation inhibition will also be presented so that mechanism of inhibition for the blended chemicals can clearly be highlighted. The generic inhibitor evaluated included vinyl sulphonates co polymer, phosphate esters, poly aspartic acid. In the lower temperature environment, it was observed that a vinyl sulphonate/phosphate ester blend was more effective than either of the components by themselves. Poly aspartic acid blende with phosphate ester also give a synergistic interaction but the performance of this chemical required higher treatment rates than the vinyl sulphonate co polymer blend. At higher temperature the overall treatment rates were reduced as the sulphate scale saturation values were reduced and the synergistic effects of the polymers and phosphate ester blends were evident. As well as classic static bottle tests performance tests were carried out in the presence of reservoir solids with stirring to further understand if the interaction of the generic chemicals within the blends with suspended solids would reduce the observed performance in the solids free test solutions. The current regulatory challenges with REACH mean that the methods outlined in this study offer the potential to reduce chemical treatment rate, cost and environmental impact by evaluating the synergistic interaction of the current range of commercially available scale inhibitors so cutting out the very high registration costs/ time delays to the market associated with new molecule development.

As waxy crude oil comes to the surface, it will cool down and causing the waxy fraction to gel. The gelled crude chokes the well, leading to restricted or blocked production and costly downtime for operators. One of the most common chemical solutions to address the wax deposit challenge is the addition of wax inhibitors or pour point depressants (PPDs) to the production stream. However, most of the PPD's used in the field are organic solvent-based polymers, which require large quantities of hazardous organic solvents such as xylene and toluene. To propose an improved solution, a water-based amphiphilic PPD polymer dispersion system, synthesized using controlled radical polymerization technology has recently been developed. This specifically designed block copolymer is synthesized with a hydrophilic polymeric head group and a hydrophobic tail. The macromolecular design was specifically optimized to control particle size to create unique and stable amphiphilic PPD dispersion. The viscosity of the PPD, at high activity of about 40%, is between 200 and 250 cps at room temperature with a milky color, and it remains stable to 200°C under 500psi. Also, the PPD dispersion itself has a pour point of −30°C, and it can be easily formulated to be pumpable under −40°C. For performance evaluation, the water-based PPD dispersion was tested using a standard cold-finger apparatus and a pour point tester on crude oils from various global regions. The results showed that this PPD dispersion not only significantly reduced crude oil wax deposition by nearly 70%, but it also reduced the pour point of the crude by typically 18°C. Overall, the current research performed on macromolecular architecture design shows that this block polymer technology allows polymer adjustment to meet application needs for various crude types, and to tackle this important flow assurance challenges.

Scale inhibitor (SI) squeeze treatments in carbonate reservoirs are often affected by the chemical reactivity between the SI and the carbonate mineral substrate. This chemical interaction may lead to a controlled precipitation of the SI through the formation of a sparingly soluble Ca/SI complex which can lead to an extended squeeze lifetime. However, the same interaction may in some cases lead to uncontrolled SI precipitation causing near-well formation damage in the treated zone. This paper presents a detailed study of the various retention mechanisms of SI in carbonate formations, considering system variables such as the (carbonate) formation mineralogy, the type of SI and the system conditions. Apparent adsorption (Γ app ) experiments, described previously ( Kahrwad et al. 2008 ), are used to show when the SI/substrate interaction is pure adsorption (Γ) or coupled adsorption (Γ)/precipitation (∏). Experiments were performed for different SIs at various operational conditions, i.e. initial pH values, minerologies - calcite, limestone and dolomite - and temperatures; the overall results from these coupled Γ/∏ experiments are summarised in Table 3 . The SI species used in this study included 1 phosphonate (DETPMP), 1 phosphate ester (PAPE) and 3 polymeric scale inhibitors (PPCA, PFC, VS-Co); the full names of these SIs are given in the paper. All precipitates were studied using Environmental Scanning Electron Microscopy/Energy Dispersive X-Ray (ESEM/EDX) and Particle Size Analysis (PSA). These measurements confirmed that when precipitation occurred, it was mainly in the bulk solution and not on the rock surface. For all SIs, both adsorption (Γ) and precipitation (∏) retention mechanisms were observed, with the dominant mechanism depending on SI chemistry, temperature and mineralogy. Differences were observed between the "apparent adsorption" (Γ app ) levels of polymeric, phosphonate and phosphate ester scale inhibitors, as follows: For the polymeric SIs (PPCA, PFC and VS-Co), the highest retention levels were observed at low pH for all carbonate substrates, due to the increase in divalent cations (Ca 2+ and Mg 2+ ) available from rock dissolution for SI-M 2+ precipitation. For phosphonate (DETPMP) and phosphate ester (PAPE) SIs, the retention level was greatest at higher pH values, as the SI functional groups were more dissociated and hence available for complexation with M 2+ ions. The polymeric VS-Co showed the lowest amount of precipitation (Γ app ~ 1.2 mg/g) in contact with dolomite substrate due to the presence of sulphonate groups (low pK a ); indeed this showed low Γ app which was predominantly pure adsorption. However, a small amount of precipitate was observed by ESEM/EDX and PSA. For polymeric inhibitors, the retention level (Γ app ) was highest on calcite (highest relative calcium content), followed by limestone and then dolomite. Phosphonate and phosphate ester SIs showed the highest retention levels on dolomite (higher final solution pH and more SI dissociated), followed by limestone and calcite. For all SI species, higher retention (more precipitation, ∏) was observed at elevated temperature. At lower temperatures, a more extended region of pure adsorption was observed for all SIs. The information presented in this study will help us in SI product selection for application of squeeze treatments with longer squeeze lifetimes in carbonate reservoir based on mineralogy and reservoir conditions. In addition, this study provides valuable data for validating models of the SI/Carbonate/Ca/Mg system which can be incorporated in squeeze design simulations.

Scale inhibitor (SI) analysis is an extremely important part of scale management and, in recent years, much work has been done on the development of specialist scale inhibitor analysis techniques like Liquid Chromatography Mass Spectroscopy (LCMS) to push the boundaries of low level scale inhibitor detection. However, LCMS requires costly and complex instrumentation and there was therefore still a need for the development of other advanced techniques like fluorescence (F) and Time resolved Fluorescence (TRF) that can be used on site to provide near "on line" data. Fluorescence techniques are particularly suited to tagged polymers and naturally fluorescent molecules like polyamines whereas the operation principle of TRF is based on interactions between lanthanide ions and various functional groups of polymer or phosphonate scale inhibitors. Both techniques work individually or in combination and this provides a distinct advantage for multiple scale inhibitor analysis in produced brines that enable the design of packages of different products for specific field applications. In addition, TRF and fluorescence techniques offer the capability of on-site detection compared to the majority of scale inhibitor analysis techniques and other advanced methods like LC-MS. The ability to detect both phosphonate and polymeric scale inhibitors at very low MIC (<1ppm) has the potential for significantly extending scale squeeze lifetimes. This has now also allowed highly efficient, F tagged polymers, to be used in field situations where scale squeezing was either stopped or the lifetime was significantly compromised because of the lack of confidence in the residuals analysis. Specific field and theoretical examples from both sub-sea and conventional wells will be presented where the application of both advanced fluorescence and TRF techniques has shown significant improvements in scale management. This paper will compare and contrast the pros, cons and limitations of both fluorescence and TRF techniques for both phosphonate and polymeric scale inhibitors. In addition, it will highlight examples where scale management significantly improves through the application of Fluorescence and/or TRF scale inhibitor analysis techniques in complex production scenarios.

Iron sulfide scaling can pose a significant threat to flow assurance, especially in sour production systems that yields hydrogen sulfide (H 2 S). When compared to conventional carbonate and sulfate scales, iron sulfide is difficult to inhibit and various risks (liberation of H 2 S) are associated with chemical removal. Moreover, efficacy of chemical treatment is poor and often uneconomical; and there is currently no true nucleation inhibitor of iron sulfide identified. A strictly anoxic static bottle test setup was developed and various traditional scale inhibitors, such as phosphonates, carboxylic acid polymers, as well as new chemistries were screened for iron sulfide nucleation and growth inhibition. Different concentrations of scaling ions (Fe +2 and S 2- ) were used to mimic the field to field variation in brine composition. The resulting aqueous phases as well as iron sulfide solid products were characterized using various analytical tools including ICP-OES, particle size analyser and Turbiscan. As expected, conventional scale inhibitors did not show any inhibitory or dispersive effect towards Iron sulfide under tested laboratory conditions. However, a chemistry is identified which can prevent iron sulfide scale deposition at threshold quantities. Specifically, this novel chemistry showed partial iron sulfide nucleation inhibition at early stages and growth inhibition (as high as two orders of magnitude) later. This significant growth inhibition of iron sulfide resulted in excellent dispersion formation that prevents iron sulfide particle aggregation/deposition. Various studies were conducted to understand the chemical-iron sulfide particles interaction and mechanistic aspect of chemical-iron sulfide interaction is identified and discussed. Currently inhibitor packages are being developed for field trials and results will be the subject of future publications. Efficient mitigation of iron sulfide scaling problem has huge industrial and economic importance in oil and gas production. Based on our current laboratory results, it is anticipated that this chemistry will provide a novel chemical treatment option for iron sulfide scaling control at threshold level whereas orders of magnitude more of conventional scale inhibitors may be required. In addition, this novel chemistry also showed promising outcomes on oil-water partitioning test by making finely dispersed iron sulfide particles water-wet thereby preventing the formation of iron sulfide-crude oil emulsion/pad.

The success of carbonate acidizing depends on the selection of proper fluid recipes, reservoir formation parameters, job design, and execution. Analysis of flowback spent acid will improve the acidizing process in future treatments, enhance the designed recipes and treatment design. The objective of this paper is to share the flowback analysis methodology following carbonate acidizing treatments with focus on solid analysis. Microstructural analysis with advanced microscopy and spectroscopy analytical techniques such as high-resolution environmental scanning electron microscopy (ESEM), energy dispersive X-ray microanalysis (EDX) and X-ray diffraction (XRD) techniques were utilized. Flowback samples were filtered through 0.45 µm filter paper. ICP was used to analyze the flowback samples. The injected acid recipes dissolved significant amount of calcite. The maximum calcium concentrations in flowback samples were 90,000-120,000 mg/L. Moreover, solid precipitates were found in flowback samples associated with pH values of 4.7-5.5. Gypsum was the dominant compound in the samples analyzed while the other compounds such as Lepidocrocite, Magnetite, Quartz, and Barite were detected in a single sample. The iron-based compounds were detected in the beginning of flowback period. Calcium and silicon rich compounds were identified in later flowback periods. The source of iron was identified to be most likely mill scale. Barite and Quartz were found to be associated with iron-based compounds. Gypsum and sodium chloride were detected with varying dominations between CaSO 4 and NaCl compounds with a possible correlation as described by Dourba et al. (2017) . Particles agglomerations were mainly associated with calcium, chloride and sulfate-based compounds. The rod-like and hexagonally-shaped particles were mainly found to be Si-based particles. Flower particles and dendrite structures were detected and probably associated with Gypsum precipitation amorphous and hemihydrate intermediates. The varying structures and agglomerations of sulfate compounds detected by the SEM indicated they were formed via different mechanisms and environments.

The practice of squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. The simple mechanism of inhibitor retention, adsorption/desorption has been complemented over the years by enhanced adsorption via mutual solvent and full precipitation of the active inhibitor onto the mineral surface of the reservoir. Previously published studies have shown that the retention of phosphonate scale inhibitors in sandstone reservoirs can be enhanced through the addition of a ‘squeeze life enhancer’. This chemical, typically, a highly charged, low molecular weight polymer can be applied in either the preflush or overflush stage of the scale squeeze treatment. To date these studies have been conducted using low temperature (85°C) sandpack testing. This paper details the laboratory work carried out under high temperature (146°C) field conditions to qualify the use of the squeeze life enhancer for field application. The results of the formation damage/inhibitor return corefloods using an MEA phosphonate (EABMPA, Ethanolaminebis(Methylene Phosphonic Acid)) and polymeric squeeze life enhancer additive are presented. The coreflood results indicated that the addition of the additive within the overflush stage of the squeeze program resulted in a 19% extension of the inhibitor lifetime. The ability to extend the squeeze treatment was translated into reduced injected squeeze fluid treatment volume as injected fluid volumes was an issue for the wells being treated and therefore reduced associated oil deferment costs. The paper will also present field data obtained from the initial two field trial treatments which were carried out in a North Sea field. The trial well had been treated more than ten times previously with the same MEA phosphonate as applied in the enhancer trial making direct comparison of the treatment performance possible. The treatment program applied to the wells resulted in no change to the clean-up rates of the treated well and no process upset during well reflow. The initial scale inhibitor returns from the field trial treatments showed the expected improvement suggested from the coreflood study. The study brings value to the industry by providing the process to follow for qualifying and trialling a new technology in a challenging high temperature scaling environment with the results from the field supporting the carefully designed chemical selection and evaluation program.

Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation. This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C. This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions. The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator. A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible in situ geochemical reactions (precipitation, dissolution, ion exchange) and account for observed ion trends. The model predicts that the process, which is beneficial in terms of reducing the scale risk, is more pronounced at higher temperatures. It has been observed previously that high temperature (130°C) chalk reservoirs may act as natural sulphate reduction plants during seawater flooding, reducing sulphate scaling and souring risks, and so reducing the operating costs (scale squeeze treatment frequency, chemical volumes) of these fields. This work illustrates new evidence of magnesium depletion and sulphate retardation above levels expected for just brine/brine interactions for a 130° C sandstone reservoir with the implication that the geochemical reactions may lead to reduced operating costs (in terms of squeeze treatment volumes and treatment frequencies) in sandstone reservoirs with low carbonate mineral content that are undergoing seawater flooding.

In this work a new laser-hydrothermal apparatus is designed to evaluate nucleation of scale minerals at temperature up to 250°C, its reliability is proven by measuring induction time data of barite from 90°C to 250°C at various Saturation index (SI) values, with the objective that such a design would contribute to the scale-related research at extreme temperature. Background solution (e.g. 1m NaCl) in a borosilicate glass bottle was placed inside a hydrothermal reactor. GC oven was used for temperature control and a modified Nd-Fe-B magnetic stirrer under the oven was used for stirring. A PFA tubing was selected to be the part with contact with solution for corrosion control. Using a 0.5 ml sample loop in two separate 6-ways switch valves, Ba 2+ and SO4 2- concentrated solutions were simultaneously injected into a background solution. After supersaturation was initiated, a laser beam penetrated through the sight glasses installed on the both sides of the reactor to record the turbidity change during the nucleation process. Induction time (tind) of Saturation index (SI) values from 0.34 to 1.02 was measured at temperatures from 90°C to 250°C. Data correlates well with data from previous laser test at 90°C in a regular beaker experiment. The induction time (tind), that is, how fast a supersaturated solution induces nucleation and crystal growth to form detectable turbidity, decrease with temperature at a fixed SI value. For example, tind of 93 minutes at 150°C decreases to about 2 minutes at 250°C under the the same SI value of 0.65, indicating that increasing temperature facilitates the nucleation process at certain supersaturation levels. This temperature impact can be attributed both by thermodynamics and kinectic aspects.

Water, oil and solid field sample characterizations are essential to scale management, corrosion and flow assurance surveillance. From sample collection to getting lab test results take weeks to even months for off-shore locations, while operation changes can happen in hours or days. During the sample transportation process, water and solid samples are often oxidized with iron species dropped out of solution or changed to oxide. For fast operational feedback and "freshest" sample measurement, on-site composition analyses are highly desirable. Typical lab analyzers, such as ICP (inductively coupled plasma) and IC (Ion Chromatography), are highly specialized and requires regular chemical supplies and maintenance. So many lab analyzers are not suitable for on-site use. This paper reports the development of test methods using a benchtop X-Ray Fluorescence (XRF) analyzer for oil field samples and field application at Gulf of Mexico offshore locations. The Benchtop XRF analyzer is very user-friendly, requires minimal sample preparation, and leaves little room for human error. Once set up, the analyzer provides fast on-site feedback at low cost, and can work with all non-gas samples. With calibrated methods, this analyzer can provide quantitative measurement for elements in water or oil. For other sample types, such as solid, slurry, mix and metals, this analyzer can be used to do qualitative measurements for trending and component identification. This on-site surveillance tool has proven to be able to provide fast and accurate data on key elements for scale, corrosion and flow assurance management at a low cost. Examples of operation decisions based on this analyzer results will be presented. This tool has demonstrated the ability to provide timely data for preventing plugging/fouling, checking chemical effectiveness, improved integrity surveillance and well flowback surveillance. Use of this tool during maintenance/turnaround helps to build up a better picture on areas with various deposits.

On the Vega gas condensate and oil field in the Norwegian North Sea, two high temperature, high pressure (HTHP) gas condensate wells on one subsea template in 370 m water depth were acid and scale inhibitor treated in order to improve productivity by acid scale removal and prevent future scaling. Significant amount of work was undertaken on design and qualification of the treatment fluids. In order to reduce operation time and increase efficiency, a novel one-time connection concept was utilized. During the operations, wells were kicked off after energizing with gas bullheaded from the neighbouring well. The treatment fluids were designed to reduce consequences for the host facility due to H 2 S generated during the operation - this required optimization after understanding of the H 2 S source as witnessed in prior treatments. The new concept with one-time connection was successfully employed and allowed for three subsequent well treatments in a row, thus saving at least two days vessel operations time. The gas injection from the neighbouring well - the one not treated at the moment - allowed for an efficient start-up of the treated well without need for larger nitrogen injection which would have led to contamination and potentially to flaring due to off-spec gas. The introduction of a batch with pH neutralizer and H 2 S scavenger batch into the treatment design to be placed into the production pipeline reduced H 2 S liberation and production to the host facilities, thus limiting the operational stress on the platform. Productivity of well A1 showed an immediately significant increase after the operations, whereas productivity of well A2 required a longer clean-up than originally anticipated.

Iron Sulfides scale has been a critical problem for oil and gas wells for several decades. One of the best candidates to remove these scales is tetrakis(hydroxymethyl)phosphonium sulfate (THPS). Most studies on the dissolution of iron sulfide scale using THPS have been done at neutral or acidic medium. Such conditions lead to a high corrosion rate when THPS is used in tubular wells. However, this work aims to give a holistic view on the pH effect, especially in alkaline medium, on the ability of THPS to dissolving iron sulfides. A combined approach of experimental and computational methods is used to get a better understanding of the pH effect on THPS ability to dissolve pyrite. Both experimental and theoretical techniques suggest that the pyrite dissolution ability of THPS decreases as pH increases. Conversely, combing THPS with EDTA (Ethylenediaminetetraacetic acid) proved effective in dissolving a mixture of different iron sulfide field scales. EDTA is a basic chelating agent which gave a pH of 8 when combined with THPS giving a slightly alkaline solution. For the field scale the combined formulation of THPS and EDTA yielded more than 70 % scale solubility however, for pure pyrite it was less than 10%. This implies that THPS and EDTA combination is effective in dissolving other iron sulfide scales, such as pyrrhotite (Fe 7 S 8 ) and troilite (FeS) which are more soluble in comparison with pyrite. Also, THPS with Di-ethyline Tri-amine Penta Acitic acid (DTPA) formulation was tested and resulted in slightly lower solubility compared to THPS/EDTA formulation. Moreover, oilfield scales are usually a mix of a variety of minerals and not only pyrite. Hence, using THPS in combination with EDTA to attain a basic pH would reduce the corrosion rate and subsequently reduce or eliminate the need for corrosion inhibitors.

Polymeric scale inhibitors used for scale squeeze treatments to control downhole inorganic scale don't perform well when pumped into the reservoir due to the poor adsorption properties on the rock surface. However polymeric inhibitors are more temperature stable than phosphonates and have higher tolerance to elevated cation compositions in the water. Therefore, a new chemistry composed of metal nanoparticles coupled with a polymeric scale inhibitor was developed to improve the squeeze life. The use of nanoparticles in the oilfield has increased in recent years; this development shows how nanoparticles can be used to increased surface area and retention of scale inhibitor in the reservoir. Metal nanoparticles were selected because of their low environmental toxicity and low formation damage potential during injection and flowback. A fast and efficient synthesis method was developed to create a novel chemistry that couples nanoparticles with polymeric inhibitors to produce a product that it was hoped would have excellent squeeze properties in multiple rock permeabilities and compositions. Core flood experiments were conducted on intact core under onshore Permian conditions of temperature pressure and brine composition as well as conditions simulating an offshore conventional field (results will be reported separately). The experimental results will be presented to show the extended squeeze lifetime of the new product in comparison to a traditional polymeric scale inhibitor retained by adsorption and also will give insight into the mechanisms by which the nanoparticle/scale inhibitor enhances squeeze life, both by increased adsorption as well as prolonging release of scale inhibitor. The product developed is able to significantly increase the squeeze life of polymeric scale inhibitors by up to 10x depending on the minimum inhibitor concentration required. The retention of the inhibitor into the rock is significantly increased, while the release is controlled at above minimum effective concentration for extended periods. The theoretic explanation for this is a metal-inhibitor bond, proprietary to the product that allows for continuous release of inhibitor into the solution, without release from the rock. Traditional squeeze returns have a Freundlich isotherm, this product also follows a similar return curve, however does not suffer from the high concentration release at the beginning of the treatment flowback. These results show that nanoparticles can be used in the oilfield to enhance existing scale inhibitors as well as create new combination products that can improve performance. Use on nanoparticles in the oilfield is an evolving topic that has significant room to grow and expand into multiple areas of oilfield chemistry. This study showcases the application of nanoparticles to enhance performance of polymeric scale inhibitors for squeeze application while maintaining a cost effective product that is environmental responsible.

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

Scale formation that can hinder continuous oil production is a serious problem in oilfield. Among all common scales, barite and calcite are two of the most important scales. Scale inhibitors have been widely added to prolong the induction time of scales. This study evaluates the methods and previous inhibition models to measure and predict scale formation in the presence of phosphonate and polymer inhibitors under common brine conditions. Turbidity measurement with laser light was used accurately and quickly to measure the induction time, and good reproducibility can be achieved between different sources of inhibitors. By conducting a set of independent inhibition experiments, previous models were evaluated and the demand for model improvement was carefully pointed out. On the basis of these evaluations, new ScaleSoftPizer (SSP) model was proposed by incorporating all available data under various simulated oilfield conditions (4-175°C). The new SSP barite inhibition model was more internally consistent, and the new SSP calcite inhibition model expanded the applicable temperature ranges. The new SSP model was incorporated into SSP 2019. To prove the application of new SSP model, the predicted minimum inhibitor concentrations (MICs) were compared with lab observations and field data, which shows good consistence and improvements. This study improved the prediction of MIC over wide ranges of temperature and inhibitor types, which can significantly reduce the expenses and efforts to solve scale formation problems.