bluuebunny/crossref_metadata_2025_split huggingface dataset:
Management of Scale Control in Produced Water Reinjection - The Near Wellbore Scale Challenge Overcome
Authors: Jordan M. M. 
Published: June 2018

Abstract
Formation of sulphate and carbonate scale is well understood within the hydrocarbon extraction industry with injection of incompatible water such as seawater into reservoir with significant concentration of barium, strontium and calcium. To overcome this challenge chemical inhibition has been utilized for many decades and in the past 15 years elimination/reduction of the sulphate ion source from injection seawater using sulphate reduction membranes has been employed.
This paper present laboratory work to qualify a scale inhibitor and field results of its application to prevent scale formation when an operator had to change from low sulphate seawater (LSSW) mixed with produced water (PW) for their water injection source to a blend of LSSW/PW and full sulphate seawater (SW). The increased level of sulphate presented a significant scale risk within the topside process on fluid mixing but more significantly increased the risk of scale formation within the near wellbore region of the injector wells which were under matrix injection rather than fracture flow regime. The qualification of a suitable inhibitor required assessment of the retention of a potentially suitable vinyl sulphonate co polymer scale inhibitors to ensure it had low adsorption and was able to propagate deep into the formation before being adsorbed from the supersaturated brine.
Coreflood studies using reservoir core were carried out to assess the scale risk of the LSSW/PW/SW brine, propagation and release characteristic of the short-listed scale inhibitors. The recommendation that followed the laboratory studies was to apply a batch treatment of concentrated scale inhibitor to each injector well to provide a high concentration pad of scale inhibitor that would be transported into the reservoir when the scaling LSSW/PW/SW fluid was injected. Protection was provided by continuous application of the same chemical at minimum inhibitor concentration to prevent scale formation within the topside and the desorption of the batched inhibitor within the near wellbore would prevent scale formation within this critical region. Thirteen injection wells were treated with a pad of 10% vinyl sulphonate co polymer scale inhibitor to a radial distance of 3 ft. prior to the start of LSSW/PW/SW injection. Highly scaling brine has been injected now for 16 months into the thirteen wells at an average rate of 25,000 BWPD per well with no decline in injector performance observed.
The lessons learned from this study are that changes in scaling potential within a PWRI system can be controlled by carrying out an assessment of location of scale formation and adoption of more typical production well scale squeezes treatment technology to protect the critical near wellbore region around PWRI injection wells.
Simulation Study for Scale Management During Shale Gas Production
Authors: Wang Xu , Mackay Eric J. 
Published: June 2018

Abstract
Hydraulic fracturing for shale gas production involves pumping large volumes of water; as a consequence of this, produced water management is an important topic to address in order to sustainably produce shale gas. It has been well documented that only approximately 10-40% of the pumped fluids will be produced back to the surface, and that there will be increased concentrations of various ions in the flowback water during this process. This flowback water, with high total dissolved solids and high concentrations of certain ions, presents a significant risk of mineral scaling (Blauch, 2009).
In general, it can be very challenging to identify the in situ formation water composition in shale reservoirs since samples of the formation water can be difficult to obtain. They may have been contaminated during the drilling process, reactions may have taken place due to fluid mixing between the injected fluid and the formation water, or simply they may not have been preserved appropriately (Pan, 2017). Some calculations of formation water compositions require to be preceded based on the observed compositional data; thereafter, the predicted formation water compositions are validated by comparison with the observed total dissolved solids (TDS) data. A two-phase 3D numerical flow model has been developed that includes a hydraulic fracture and is populated with shale reservoir properties. (This model assumes the hydraulic fracture is already established – i.e. the calculations include coupled flow and component transport, but the geomechanics are not considered). It is used to simulate fluid transport mechanisms within the shale system and to address the question – what causes the significant retention of fracture fluid in shale reservoirs. A series of simulations was performed to achieve a history match with observed flowback water data in a western Canadian basin (the Horn River Basin).
A further two-phase 3D flow model was developed to examine the scaling tendency due to the evolving produced brine composition over the lifetime of the well. It is based on the previously history matched model and includes the fracture fluid and formation water compositions to predict precipitation of minerals. Finally, scale inhibitor injection was simulated to examine the impact of inhibitor retention on well protection.
Development and Improvement of a Novel IC-MS Technique for Phosphonate Scale Inhibitors
Authors: Cheng Lei , Durnell Christopher , Linares-Samaniego Sandra , Littlehales Ian , Fidoe Julie , Casado-Rivera Emerilis 
Published: June 2018

Abstract
Accurate and precise analysis of scale inhibitor residuals is important to managing oilfield squeeze treatments. Phosphonate scale inhibitors are effective for the prevention and control of scale problems in oilfields. The traditional analytical technique for monitoring phosphonate scale inhibitor residuals is inductively coupled plasma optical emission spectroscopy (ICP-EOS). ICP-OES is simple and has been used for monitoring squeeze treatments for decades. However, it can only measure the total phosphorus in the system and is unable to differentiate the different forms of phosphonates in commingled samples.
This paper presents a novel technique using ion chromatography and mass spectrometry (IC-MS and IC-MS/MS) for monitoring and quantifying different phosphonate scale inhibitors with high sensitivity and specificity. Ion chromatography efficiently separates phosphonate ions from other salt ions, and mass spectrometry speciates and quantitates molecular ions or fragment ions of each phosphonate. Previous work in our group (Zhang, et.al., 2014) had shown that IC-MS could be used to differentiate two phosphonates in a squeeze treatment using the characteristic molecular ions of each phosphonate. As the complexity of the squeeze treatment increases with the addition of other phosophates to the local oilfield, the development of an advanced IC-MS/MS method has been required to differentiate up to four phosphonates in a single commingled sample. This innovative technique has a detection limit of &lt;1 ppm for each phosphonate in the mixture. The technique has been validated using both synthetic brine and field brine. Solid phase extraction cleanup work has also been performed to improve the capability of the technique in high-salinity brines. This novel analytical method will provide a powerful tool in squeeze scale management for subsea and deepwater oilfields.
Rigorous Carbonate and Sulphide Scale Predictions: What Really Matters?
Authors: Ness G. , Sorbie K. S. 
Published: June 2018

Abstract
Predicting the formation of pH- dependent scales such as carbonates and sulphides requires a full calculation of all hydrocarbon and aqueous phases present to determine the distribution and speciation of CO2 and H2S in the system. Several commercially available software packages combine PVT calculations with scale predictions, but such packages are more targeted to aqueous systems and have limited hydrocarbon capabilities. Likewise, PVT modelling software focusing on the hydrocarbon phase does not always fully model the aqueous phase or can only predict a limited number of scales/complexes. Moreover, within each software we can select a large number of different Equations of State (EOS), activity models, equilibrium parameters etc., which may ultimately impact the final carbonate and sulphide scale prediction profile. The questions we try to answer in this work are: How important is the software selection and which parameters really affect the final scale prediction profiles? In what scenarios do these values matter and when are they not important?
In previous publications we laid out a clear rigorous procedure (workflow) for the prediction of carbonate and sulphide scales which can be applied using any commercial PVT and scale prediction software. Here we apply this general workflow using different software and EOS models to evaluate their impact on the final carbonate and sulphide scale prediction profiles for some specific carbonate/sulphide field scaling scenarios. The results show that despite the large number of modelling options available, there are two parameters that play a key role in pH-dependant scale predictions: partition coefficients of CO2 and H2S between gas, oil and water and the relative mole (and volume) distribution between each phase at selected temperature and pressure. The final scale prediction results can be accurate only when these values are accurate, irrespective of how they are obtained. This work shows the impact of choosing different software and equations on carbonate and sulphide scale predictions, not just as a "black box" software comparison exercise but with a clear connection between the aqueous and hydrocarbon phase thermodynamics, the scaling system and the final results.
Development and Field Application of an Iron Tolerant Scale Inhibitor for use in Fracturing Completions and Production
Authors: Davies H. , Toole M. , Higgins R. 
Published: June 2018

Abstract
Produced waters are increasingly found to contain high levels of dissolved iron, with typical ferrous iron concentrations ranging from a few ppm to several hundred ppm. The presence of iron can cause issues in production, one problem being a detrimental effect on the performance of scale inhibitors. The aim of this work was to investigate scale inhibitor chemistries with improved iron tolerance, and apply a new product in the field to address a severe inorganic scale issue that had been encountered.
Using static bottle tests to assess brine compatibility and anaerobic dynamic scale loop tests to assess scale inhibition efficiency, a wide variety of scale inhibitor chemistries containing different functional groups were screened. The aim was to identify an inhibitor which would give the best performance against calcium carbonate scale in the presence of up to 100ppm Fe2+. Previous studies have shown that the inhibition of calcium carbonate scale is more adversely affected by the presence of iron than the inhibition of barium sulfate scale, and as calcium carbonate was the main challenge in the field case the emphasis was placed on inhibiting this scale type.
Initial compatibility studies revealed the additives with the best brine compatibility, and around nine additives were taken forward for performance testing. It was found that acrylic acid based copolymers demonstrated reasonable scale control at 5-20 ppm Fe2+, but at higher iron the high dose levels required meant that the limit of compatibility was reached before complete scale control had been achieved. The best performing additive for calcium carbonate was found to be a phosphonate derivative. A field trial was conducted in a predominantly calcium carbonate scaling environment as a proof of concept and scale inhibitor residuals were monitored over a 5-month period. After this successful study, further lab experiments were performed with the chosen inhibitor to demonstrate good calcium carbonate control in the presence of up to 100 ppm Fe2+.
A comprehensive investigation of different scale inhibitor types resulted in an optimum chemistry to control calcium carbonate scale in the presence of high concentrations of ferrous iron. Applying this chemistry in the field has demonstrated better scale control than was being achieved with the previous scale inhibitor.
Development of the First Readily Biodegradable OECD306 Phosphonated Amino Acid Chemistry for the Control of Calcium Carbonate and Calcium Sulphate in HTHP and UHT Unconventional Productions
Authors: Di Toto Raul Antonio , Bruyneel Frederic , Parravicini Davide , Kan Amy T. , Tomson Mason B. , Yan Fei 
Published: June 2018

Abstract
The paper describes the development of the first readily biodegradable - in seawater - phosphonated amino acid chemistry (PHAAC), which is able to control calcite and calcium sulphate scale under unconventional HTHP1 conditions (simulated Shearwater field conditions and T/P up to 250°C/1,000bar). This novel chemistry is aimed to support unconventional and ultra HTHP productions in a cost-wise sustainable manner.
The chemistry development is described from the selection of the suitable chemical functionalities through the evaluation of the "must have" properties – brine compatibility, thermal resistance, eco-toxicity profile – to the assessment of performance for calcite, calcium and barium sulphate by dynamic and static scale inhibition tests under uniquely severe conditions (T= 55°C-250°C, salinity = max. 250,000ppm, Calcium = max. 18,960ppm). Successful squeeze simulation was tested at high temperature with a high Ca connate water. Software simulations - Pitzer electrolyte theory - were used to preliminary screen out and define conditions.
The novel chemistry, when compared to industry benchmark inhibitors from low (55°C) to ultra high temperature (250°C), showed an extremely positive overall performance gap. The product thermal resistance evaluation and its impact on chemical stability, properties and performance, is presented showing that stability of the chemical structure - only 1.3% degradation after 7 days at 160°C - eliminates the performance drop when conditions get severe. Minimum inhibitor concentration of the novelty chemistry is up to 10 folds less than conventional chemistries in dynamic scale rig tests and squeeze life is excellent, allowing remarkable cost saving in treating scale in extreme conditions. Detrimental effect of Fe++ on performance and chemical compatibilities are also assessed. Negligible toxicity against marine species and readily biodegradability in seawater makes the chemistry suitable for offshore operations in OSPAR countries. Presented results coupled to ease of detection proof that the new experimental environmentally friendly scale inhibitor can be successfully deployed in HTHP applications for the control of calcium carbonate and calcium sulphate under extremely severe regimes.
The novel chemistry is the first readily biodegradable (OECD306) phosphonate for scale inhibitor applications in HTHP unconventional conditions. It sets new levels of performance in the control of frequently encountered scale types in O&G. The documented inhibitor properties and performance, confirm that it can be a game changer for flow assurance strategies in unconventional productions.
Scale Management in Monoethylene Glycol MEG Systems - A Review
Authors: Seiersten Marion , Kundu Shiv Shankar 
Published: June 2018

Abstract
The paper reviews operational issues that arise when MEG is used for hydrate inhibition, especially when it is regenerated and recirculated. Thermodynamic equilibrium software can assess the scaling risk to some extent. Utilisation of data on nucleation and growth of scale formers like calcium carbonate can enhance the accuracy of the predictions.
The presence of MEG and the conditions encountered in MEG systems favour aragonite crystallisation when the MEG solutions become supersaturated in CaCO3. MEG retards the growth rate of all three CaCO3 polymorphs, but the reduction is smaller for aragonite than for calcite and vaterite. The growth rate of siderite is also slowed down by MEG. However, MEG does not inhibit the nucleation and growth of carbonates.
Alkalinity in recycled MEG will enhance the scaling risk downstream of the MEG injection point when there is calcium in the produced water. Scale can be mitigated by scale inhibitors, but the selection process must ensure that the chemicals are tested at relevant conditions; i.e. with the expected MEG concentration, alkalinity and pH.
Many MEG recovery units have a pre-treatment system for controlled removal of carbonates and to some extent hydroxides. This reduces the amount of scale that may form in the regeneration system. In the pre-treatment, alkalinity dosed as hydroxide and/or carbonate forces precipitation of calcium, strontium and iron carbonates and magnesium hydroxide. The supersaturation is generally so high that scale inhibitors are not able to prevent precipitation of the solids.
Simulating Squeeze Treatments in Wells Completed with Inflow Control Devices
Authors: Kaur Amarpreet , Stalker Robert , Graham Gordon M. 
Published: June 2018

Abstract
The advent of wells with extremely long producing intervals, extended-reach and multilateral wells, typically completed in heterogeneous formations, brings with it challenges regarding completion design to maximize overall production in a sustained manner. Judicious placement of Inflow Control Devices (ICDs) can ensure a more even inflow of fluids along the full length of the interval, delaying water or gas breakthrough and in some cases restricting water production. Such devices also influence the placement of chemical treatments, such as scale-inhibitor "squeeze" treatments, which in turn affects the subsequent treatment lifetimes and efficiency.
This paper presents a new analytical model to explicitly simulate the effect of ICDs on squeeze treatments and, in particular, on treatment placement and consequent lifetimes. The explicit method of modelling ICDs, which is based on Bernoulli's theorem of constricted flow through a pipe, is compared with other implicit phenomenological approaches, such as modelling the effect of an ICD as a damaged region using a dual-permeability model. By this comparison, the relevance of dual permeability modelling for simulating ICDs is presented. The relationship between chemical placement and inhibitor return has been clearly demonstrated in other publications (James et al., 2005, Sorbie et al. 2005). This paper illustrates the additional effects that ICDs bring to the placement challenge, highlighting the key parameters that can influence the zonal injectivity behaviour. The presence of ICDs in the well is shown not only to benefit the well's inflow profile during production but can also favourably influence the outcome of squeeze chemical treatments.
In summary, the paper describes the development of an important new tool to assist in the design of optimum chemical treatment strategies in wells completed with ICDs, without the need to use more complex reservoir simulators for near-wellbore treatment in complex completions.
Iron Sulphide Inhibition and Interaction with Zinc and Lead Sulphide
Authors: Al-Harbi B. G. , Graham A. J. , Sorbie K. S. 
Published: June 2018

Abstract
Iron sulphide (FeS), zinc sulphide (ZnS) and lead sulphide (PbS) are considered to be among the most challenging scales in terms of inhibition and removal. They can form by direct reaction of aqueous sulphide species with dissolved Fe, Zn and/or Pb and by the exchange between aqueous sulphide species with preformed iron compounds, such as iron oxide hydroxide. These existing iron compounds may have formed during production and/or intervention, such as an acid treatment. Similarly, PbS and ZnS can form by extracting sulphide from a more soluble sulphide scale i.e. Zn exchanging with Fe in FeS. The objective of this work was to investigate FeS formation and inhibition under a range of conditions including pH, temperature, salinity and proposed mode of formation. In addition, the interaction between iron, zinc and lead within solutions containing sulphide species was investigated
The majority of this study was conducted under anaerobic conditions, with the scale formation and/or inhibition experiments being monitored by inductively coupled plasma (ICP) analysis, pH and particle size measurements. Among the tested scale inhibitors, two showed high efficiency against iron sulphide, however high pH and salinity had a detrimental impact on the performance of one of these products. Interestingly, these scale inhibitors prevented iron sulphide deposition even under aerobic conditions i.e. iron hydroxide partially preformed. Moreover, at sufficiently high concentrations of scale inhibitor, the deposition of zinc sulphide and lead sulphide was prevented even when these scales were formed via cation displacement i.e. zinc and lead displaced sulphide ions from pre-formed iron sulphide. The route of formation for FeS, ZnS and PbS was seen to have a significant impact on the inhibition process.
The particle sizes of inhibited (suspended) FeS were significantly lower than the blank FeS samples, with this effect increasing with increased scale inhibitor concentration. This difference in particle size may have an important influence on in-line filter blocking tests and produced water quality issues.
Application of Electroless Nickel Coating as a Scaling Resistant Alloy in Thermal Production
Authors: Zhu Da , Gong Lu , Qiu Xiaoyong , Hu Wenjihao , Huang Jun , Zhang Ling , Fattahpour Vahidoddin , Mahmoudi Mahdi , Luo Jing-Li , Zeng Hongbo 
Published: June 2018

Abstract
The scaling has been found to be a major problem in thermal production, such as in the Steam-Assisted Gravity Drainage (SAGD) operation. In addition to providing a favorite environment for corrosion, scaling could result in extreme plugging in sand control devices. Therefore, any coatings for the equipment and completion in thermal production should provide significant anti-scaling surface properties.
This paper presents a detailed study, including field and laboratory testing, on application of the Electroless Nickel Coating (EN-coating) in thermal production environment. Initially, EN-coated and uncoated carbon steel samples were tested in laboratory to assess the scale, hardness and adhesion of inorganic and organic materials.
Successful laboratory testing lead to a field testing plan, which involves deploying the EN-coated and uncoated samples into a horizontal well for thermal production. The specimens were recovered after certain time and a comprehensive X-ray Photoelectron Spectroscopy (XPS) and Energy-Dispersive Spectroscopy (EDS) were performed to assess accumulation of fouling substances on EN-coated and uncoated carbon steel.
This study suggests the application of the EN-coating technology to solve the problems caused by scale, and adhesion of organic and inorganic material in thermal production. The comprehensive laboratory testing and field data from the SAGD wells shows that EN-coating significantly improves the well integrity in the harsh thermal production environment.