bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improvement of Thermodynamic Modeling of Calcium Carbonate and Calcium Sulfates at High Temperature and High Pressure in Mixed Electrolytes
Authors: Dai Zhaoyi , Shi Wei , Kan Amy T. , Zhang Nan , Tomson Mason B. 
Published: February 2021

Abstract
Deepwater oil and gas production plays a more important role in global energy support today in which high temperature and high pressure (HTHP) conditions usually occur. Mineral solubility predictions at HTHP with mixed electrolytes is thus getting more attention since it is critical for getting rid of scaling risks under such extreme conditions. In this study, Pitzer theory was applied to predict the solubility of gypsum, anhydrite and calcite over wide ranges of temperature, pressure, and ionic strength with mixed electrolytes. Solubility of gypsum was measured from 0 to 40 °C, from 14.7 to 20,000 psi, with 0 to 4 mol NaCl/kg H2O. Anhydrite solubility reported in literature was confirmed and adopted in this study. The equilibrium constants of gypsum and anhydrite are incorporated by the temperature dependent part reported in SOLMINEQ.88, and Atkinson and Mecik’s pressure dependent part. Based on these solubility data, equilibrium constants, and other virial coefficients, virial coefficients for Ca2+ and SO42- interactions with pressure dependence (i.e. βCaSo4(0), βCaSo4(2), CCaSo4(0)) are fitted over wide ranges of temperature and pressure (i.e. 0 to 250°C and 14.7 to 20000 psi). The solubility of gypsum/anhydrite can be precisely predicted based on the derived virial coefficients. More importantly, they can also be applied to accurately predict calcite solubility with mixed electrolytes from 0 to 250 °C (except for 100 °C) and up to 21000 psi. Based on the βCaSo4(2) values derived in the calcium sulfates system, the association constant of CaSO(0) at 14.7 psi and 25 °C matches very well with that reported in literature derived based on other methods.
Systematic Study of Barite Nucleation and Inhibition with Various Polymeric Scale Inhibitors by Novel Laser Apparatus
Authors: Yan Chao , Kan Amy T. , Zhang Fangfu , Liu Ya , Tomson Mason B. , Tomson Ross C. 
Published: February 2021

Abstract
This work reports a reliable and systematic study of barite nucleation kinetics in the presence of scale inhibitors from 4 °C to 90 °C and at various conditions. In this study, we designed and developed an apparatus to study the nucleation kinetics of barite scale formation by monitoring the change of photo-current created by 5 mW, 635 nm red laser.
The photo-detector has a wide wavelength range where sensitivity has a peak at 960 nm. A set of convex and concave lens were used to control the beam diameter so that it can pass through more particles and increase the sensitivity. Temperature and mixing procedure was precisely controlled by an external water bath and magnetic stirplate respectively. The photo-current output was constant when the laser is shining through a clear solution prior to scale formation. Once scale occurred, laser was scattered by scale particles which causes the decrease of photo-current. This method can be expanded to study nucleation kinetics of other scales such as carbonates, other sulfates, and sulfide scales. In addition, it can be customized to perform study under high temperature, high pressure and anoxic conditions.
By using this newly developed “laser” method, we successfully measured the nucleation kinetics of barite in synthetic brine (1M NaCl, 0.1 M CaCl2) under various combination of reaction parameters including temperature (T), pH, saturation index (SI), and Ba2+ to SO42- ratio (R). Furthermore, the inhibition efficiency of various scale inhibitors including sulphonated polycarboxylic acid, polyvinyl sulphonate and inulin on barite precipitation has also been investigated. Based on the experimental results, the relationship of precipitation kinetics of barite as a function of T, pH, SI and R was established. Results of this study will be incorporated into the scale prediction software to predict the risk of scale formation and the efficiency of scale inhibitors.
Selection of Scale Control Strategy on a Sub Sea Developed Field in the North Sea and How 6 Different Companies Contributed
Authors: Sørhaug E. , Jordan M.M. , McCartney R.A. , Stalker R. , Mackay E.J. , Green J. 
Published: February 2021

Abstract
The Blane field is a sub-sea oil and gas production development located in the southern part of the North Sea straddling the UK and Norwegian border. The field is expected to produce inorganic scale (BaSO4) when injection water containing sulphate breaks through in the production wells. This will require scale inhibitor squeezes from an intervention vessel to mitigate scale deposition.
The wells were completed with long horizontal sections straddling multiple producing zones. This could potentially result in scale deposition severely reducing productivity if both formation water and injection water were to be produced simultaneously into the wells. Adding to the complexity, the perforation guns were left in the wellbore as part of the completion preventing any access to the perforation area. The distribution of scale inhibitor during a squeeze pumping operation could therefore be uneven leaving parts of the well poorly protected. In addition, the guns prevent physical removal of any type of materials in the well bore like asphaltenes, sand and scale which could plug off the perforations during a pumping operation with a well intervention tool; Wireline, coiled tubing, etc..
Injection water supplied from a host platform is used for pressure support of the reservoir. During the field development, the injection water was expected to contain mostly produced water reducing the scale potential considerably as it would have low sulphate content. When water injection started, very little produced water was being produced resulting in mostly seawater being available available for pressure support. Scale deposition in the well and around the well bore could therefore prove to be impossible to control unless reactions in the reservoir would reduce the scale potential or a reliable scale inhibitor squeeze method to mitigate scaling could be identified.
This paper describes the joint effort of 6 different companies to identify the risks associated with the inorganic scaling during production and how a scale squeeze strategy was developed. The work included scale inhibitor selection, a geo-chemical study, and reservoir and near well bore simulations, sub-sea deployment selection, deciding on water chemistry and production monitoring and development of an overall management plan.
Oilfield Scale Inhibitors for Application in Precipitation Squeeze Treatments: Solubility of the Ca_PPCA Complex
Authors: Farooqui Nazia M. , Sorbie Kenneth S. 
Published: February 2021

Abstract
Chemical scale inhibitors (SI) are widely applied in the oil industry to prevent downhole scale formation in squeeze treatments. Poly-Phosphino Carboxylic Acid (PPCA) is an industry standard polymeric scale inhibitors which is often applied as a precipitation treatment, where PPCA forms a sparingly complex with calcium ions, denoted Ca_PPCA.
In this paper, we study the detailed solubility behaviour of the Ca_PPCA complex which plays an important role in precipitation squeeze treatments. We describe several novel findings on the solubility of (Ca_PPCA) complex system. Specifically,
1. The precipitated Ca_PPCA complex was isolated and used to determine experimentally the solubility of the species involved in a field squeeze for various compositions and temperatures.  2. Different fractions of PPCA have been analysed by both ICP (for P) and Hyamine (for polymeric content) and for their inhibition efficiency (IE) against barite scale. We show that PPCA “precipitate” is richer in the higher molecular weight polymer components.  3. The solubility of the precipitated PPCA/Ca complex becomes lower as it is exposed to successive fresh supernatant brine and the behaviour is very unlike that expected from a “solubility product” model.
We believe that these results are the most detailed to be published in the literature on the PPCA system and that they are of particular significance and application for all polymeric SI precipitation squeeze treatments. The significance of these results for field precipitation squeeze treatments is also discussed.
Squeezing Sub-Sea Wells Co-Mingled in the Same Flowline on the Norne Field
Authors: Heath Steve , Selle Olav Martin , Storås Elisbeth , Juliussen Bjørn , Thompson Alan , Johnston Clare , Vikshåland Kim , Lid Linn-Øydis , Gundersen Thomas , Bjellaas Thomas 
Published: February 2021

Abstract
An essential part of any scale squeeze management strategy for any oilfield is the capability to accurately and precisely determine the residual scale inhibitor concentration in the produced fluids. These data in combination with ion analysis and well productivity index are essential to determine the lifetime efficiency of scale squeeze treatments. For sub-sea wells comingled in the same flowline this presents a significant challenge due to mixed brine composition in the flowline and the requirements to analyse multiple families of scale squeeze inhibitors in the same sample without interference from the continuously injected wellhead/topside scale inhibitors and any other production chemicals that maybe applied.
In recent years the use of environmentally acceptable polymeric scale squeeze inhibitors has increased. The accurate and precise analysis of polymers has proved to be difficult and a toolbox of advanced scale inhibitor analysis techniques has therefore been developed to improve scale management capability in sub-sea fields.1 This technology is based upon a range of novel analysis techniques, including Liquid Chromatography-Mass Spectroscopy (LC-MS), which have demonstrated the feasibility to detect multiple families of scale inhibitors at low levels with improved confidence along with the potential for squeezing wells co-mingled at the same flowline with different scale inhibitors. This was not considered possible before and recent refinements have been targeted towards the specific challenges on the Norne field, where it was required to detect three different polymeric scale squeeze inhibitors in the same flow line sample in the presence of the continuously applied wellhead and topside polymeric scale inhibitor.
This paper presents brief details of the progress made with new analysis techniques and highlights the application benefits of the implementation of these novel scale inhibitor analysis techniques in the Norne field. Data will be presented from a proof of concept study for squeezing three sub-sea wells co-mingled in the same flowline with three different polymeric scale squeeze inhibitors, namely, a phosphorus containing polyamine, a phosphorus tagged quaternary amine terpolymer and a phosphorus tagged sulphonated copolymer all in the presence of the wellhead/topside sulphonate/carboxylate copolymer. The implications of different detection limits for the three different polymers on the individual well treatment lifetimes and re-squeeze frequency will also be discussed.
Prediction and Evaluation of Calcium Carbonate Deposition at Surfaces
Authors: Mavredaki Eleftheria , Neville Anne 
Published: February 2021

Abstract
Mineral scaling is one of the main flow assurance problems facing the oil and gas sector and imposes severe constraints on the economic and safe operation of many fields. During the last decades, operators, in conjunction with the chemical manufacturers and oilfield service companies have focused on understanding, predicting and mitigating scale formation. Even though progress towards better management of scale formation continues, scale precipitation is still a significant flow assurance problem, caused by changes in temperature and pressure conditions or by mixing incompatible waters (produced water, seawater, aquifers) especially at high water cuts. One of the most frequently depositing scale types in the oil production process is calcium carbonate. To date, the overwhelming amount of research has been on the thermodynamics that drive the precipitation of calcium carbonate in an aqueous system, with little attention given to actual surface deposition. Therefore, to improve scale management practices, the kinetics that dominate CaCO3 surface formation need to be understood. The work presented in this paper, has as its main focus the deposition of CaCO3 at a stainless steel surface.
The data from the surface is presented in conjunction with the findings from bulk phase experiments. A small bore flow rig and a quartz crystal microbalance were used for monitoring the induction time and the real time deposition of CaCO3. Calcium carbonate deposition was examined at a range of conditions with emphasis given to different saturation ratios (SR). The results are discussed in correlation with the theoretical calculations based on a scale prediction software.
The data collected from the CaCO3 surface experiments contribute to understanding at which level the saturation ratio becomes a threat with respect to scale formation at surfaces. This paper describes steps towards predicting the induction time of calcium carbonate at surfaces, when the main input is the saturation ratio.
Sulphide Scale (PbS/ZnS) Formation and Inhibition Tests for a Gas Condensate Field with Severe Scaling Conditions
Authors: Okocha Cyril , Sorbie Kenneth S. , Hurtevent Christian , Baraka-Lokmane Salima , Rossiter Marcus 
Published: February 2021

Abstract
Identifying effective sulphide scale squeeze inhibitors has been a major challenge in the production of oil and gas from deeper, higher temperature reservoirs. Managing sulphide scales of zinc and lead (ZnS and PbS) that commonly occurs in deep, hot reservoirs poses a significant challenge because of their very low solubilities. In general, for scaling problems applying chemical scale inhibitors or dispersants is the preferred solution to most challenges. However, to date no effective sulphide inhibitors/dispersants have been available which can deal with severe lead, zinc and iron sulphide problems at high salinity (HS &gt;200, 000TDS) and high temperature (HT &gt;180°C) conditions. It is a particularly difficult task to find sulphide inhibitors which can also be “squeezed” successfully since they must return to the wellbore at relatively high concentrations.
This paper describes various sulphide inhibitor testing techniques which have been applied to many candidate products for the management of ZnS and PbS in a gas condensate field with a known relatively severe ZnS/PbS scaling problem. The paper presents sulphide static and dynamic test measurements along with thermal ageing results that show some encouraging results in terms of ZnS/PbS sulphide inhibition. The paper extends our knowledge and ability to test effective sulphide inhibitors for severe ZnS/PbS scaling conditions in high pressure/high temperature (HPHT) reservoirs.
Post-frac Flowback Water Chemistry Matching in a Shale Development
Authors: Vazquez O. , Mehta R. , Mackay E. , Linares-Samaniego S. , Jordan M. , Fidoe J. 
Published: February 2021

Abstract
Shale developments are normally hydraulic fractured to stimulate the low permeability of the reservoirs, in order to allow fluid to flow to the wellbore. The most common fluid fracture deployed in shale developments is slickwater; which is typically composed volumetrically of approximately 95% water, 4% proppant and 1% other chemicals such as scale inhibitor, surfactant, biocide and corrosion inhibitor. Water management in shale plays accounts for 5% - 15% of total well completion costs. This study investigates the fate of fracturing fluids in shale developments and attempts to understand the effect of fracturing fluid trapped within the reservoir. Approximately 5% - 50% of fracturing fluid pumped is flowed back as the well is put on production. Scale deposition is often experienced within these wells due to the interaction of fracturing fluid lost to the formation reacting with formation brines. It is estimated that the formation of scale within the reservoir, blocks of nano-pores and reduces to some extent the fraction of fracturing fluid returned.
The main purpose of this study was to simulate the post-frac flowback composition using a reactive transport model. The model simulates the injection of the fracture fluid, when in contact with the reservoirs minerals, a number of geochemical processes take place and with subsequent production further reactions are possible. The model was used to evaluate the possible causes of the high TDS content in the post-frac water, on one hand dissolution of salts present in the shale or the breaching of deep saline aquifers during fracturing. The value of this paper being to the industry is to increase the understanding of the geochemical reactions occurring during shale fracturing which will impact produced water reuse, scale inhibitor selection to prevent inorganic scale deposition resulting in better fracture performance.
The Impact of Pre-flush Additives on Scale Squeeze Treatments - Application of Modelling and New Test Methodologies to Understand Mechanisms of Retention and Optimise Field Treatment Designs
Authors: Vazquez O. , Chen T. , Crombie L. , Chen P. , Heath S. , Guo Q. 
Published: February 2021

Abstract
One of the most common methods to prevent scale deposition in the near wellbore area is through the application of squeeze treatments which conventionally consist of pre-flush, main treatment, overflush, shut-in and back production stages. The use of additives such as polyamino acids and polyquaternary amines has often been successfully applied as part of the pre-flush stage of squeeze treatments to improve treatment lifetimes (Chen et al., 2006, Vazquez et al., 2011, Heat et al., 2012). However, although this technology has been successful applied in the field, there is still a lack of understanding of the prevalent retention mechanisms with different scale inhibitors and also a suitable test methodology and modelling techniques to optimize field treatment designs and lifetimes.
A new sand pack methodology which provides a better simulation of field squeeze treatments than traditional corefloods has been designed to provide a better understanding of the scale inhibitor retention mechanisms when polyquaternary amines are applied in pre-flush treatments. This has enabled improved treatment modelling and the impact of these additives to be understood in field treatments.
The performance of the polyquaternary amine is dependent upon scale inhibitor chemistry and the mechanisms of retention are addressed for both polymeric and phosphonate scale inhibitors. The adsorption isotherms were derived and compared in the absence/presence of the polyquaternary amine using specialized software, and applied to predict squeeze lifetime in field scenarios.
This paper provides an understanding on the effects of polyquaternary amines on squeeze lifetime for both phosphonate and polymeric scale inhibitors supported by the application of a newly developed test methodology and computer modelling techniques. In addition, the combination of laboratory and computer modelling data coupled with field experience and a better understanding of the retention mechanisms involved now provides the ability to improve and optimize field squeeze treatment designs with polyquaternary amine pre-flush additives.
Development of Novel Test Methodology to Understand the Mechanisms of Halite Inhibition and Environmentally Acceptable Halite Scale Inhibitors for High Temperature Application
Authors: Ho Kimberley , Chen Tao , Chen Ping , Hagen Thomas , Montgomerie Harry , Benvie Ronald 
Published: February 2021

Abstract
Halite deposition is most commonly observed in gas/gas condensate fields with low water cut, high TDS produced brines and high temperature. Halite is notoriously difficult to inhibit and there are limited studies focused on halite due to it being incredibly challenging to have an effective test methodology under laboratory conditions that reflect the field conditions. The mechanisms of halite inhibition are unclear.
In the published literature, static jar testing is primarily used to evaluate the performance of halite inhibitors. It is not representative of dynamic field conditions and provides limited information of halite inhibition. A new methanol driven dynamic test methodology has been developed alongside a novel jar test procedure, which together provides an effective methodology to evaluate halite inhibition under both static and dynamic conditions and provides an insight into the understanding of the mechanisms of halite inhibition.
Using these novel test methodologies, four short-listed inhibitor chemistries including environmentally acceptable inhibitors were assessed and categorised into two types based on the understanding of the mechanism.
➤ Nucleation/growth inhibitors. Inhibitors reduce the nucleation/growth of halite crystals and give good performance under both static and dynamic test conditions. ➤ Dispersion inhibitors. Inhibitor doesn't stop the nucleation/growth of halite crystals and gives poor performance under static conditions, but good performance under dynamic conditions due to dispersion effect.
Both types of halite inhibitors have been successfully deployed in the fields through continuous injection or batch treatment. Coreflood tests were carried out to confirm the potential risk of formation damage during downhole batch treatment. Other deployment methods have been discussed such as through methanol injection line as both inhibitors are fully methanol compatible.
This paper will give a comprehensive study of halite inhibition for challenged wells, including prediction, novel methodology, program of laboratory qualification, mechanism understanding and field deployment, coupled to the development of a chemical technology toolbox to design field halite applications. The value that a fuller understanding of halite control gives the industry is the ability to reduce/eliminate water wash application to control halite formation and so improve well operation time. If halite inhibition is considered at the capex phase of field development, provisions can be made for chemical injection facilities to maintain uninterrupted production.