bluuebunny/crossref_metadata_2025 huggingface dataset:
Sulfide Scale Control in Produced Water Handling and Injection Systems: Best Practices and Global Experience Overview
Authors: Wylde Jonathan J.
Published: February 2021

Iron sulfide scale is found almost ubiquitously in maturing oilfield produced water handling and injection systems. Keeping injection systems clean of sulfide scale is becoming more of a shared challenge, but there are few examples where true root cause analysis has led to specific laboratory testing and development of bespoke removal and prevention methods. This paper aims to link these aspects by sharing the best practices from around the world with cutting edge techniques and chemistries used to maintain flow assurance and injectivity in produced water handling systems affected by iron sulfide scale.

Discussion includes root causes analysis of iron sulfide scale formation and deposition mechanisms focusing on the interplay of pH, along with sources of iron and sulfide. The paper goes onto discuss laboratory and field evaluation of control methods. Finally, the root causes of iron sulfide scale formation and deposition mechanism, including the relative advantages and merits of the different techniques, including:

Chelating agents (for iron sequestration) Surfactants (for water wetting) Biocide (to target SRB and biofilm) Corrosion inhibitor (to lower iron in system) Sulfide scale inhibitors (threshold inhibition of scale)

Additionally, case histories are used to elaborate the theoretical discussion. The first case history is from an offshore oilfield water injection system, where fouling occurred due to changes in the flow assurance strategy further upstream and capture the lessons learned on the interplay of different production chemicals. The second case history concerns an onshore oilfield with a vast water injection system of over 3,000 wells supporting approximately 5,000 production wells.

The paper concludes with a summary of the decades of experience of solving the most challenging sulfide scaling scenarios, as well as cutting-edge research on a new class of polymeric exotic sulfide scale inhibitor dispersant, effective as threshold concentrations against even lead and zinc sulfide.
Sulfide Scale Control: A High Efficacy Breakthrough Using an Innovative Class of Polymeric Inhibitors
Authors: Savin A.J. , Adamson B. , Wylde J.J. , Kerr J.R. , Kayser C.W. , Trallenkamp T. , Fischer D. , Okocha C.
Published: February 2021

Prevention of sulfide scale through the use of chemistry is a developing area of focus within the oil industry. There are few examples of a single chemical approach working, where scale inhibitor species function at threshold concentrations. Partial inhibition may be provided by ‘standard’ scale inhibitors using established chemistries such as phosphonates or polymeric species. However, the efficacy of these inhibitors against sulfide scale is generally poor and high concentrations are typically required.

Based on an industry need for a true, high-performance sulfide scale inhibitor, work was undertaken to develop a novel chemistry that would offer a step-change in performance from existing technologies. Using a new advanced rapid screening technique, a wide range of ‘standard’ scale inhibitors were assessed, which proved that the majority of these chemistries display no efficacy against sulfide scale. A select few of the standard scale inhibitors displayed limited efficacy and from this data common molecular features which contributed to sulfide scale inhibition were identified.

Utilizing this knowledge, a range of novel polymeric chemistries were synthesized which provide significantly superior inhibition than any other postulated for this application. It has been possible to identify specific moieties within these complex polymers which are required for sulfide scale inhibition and to theorize on likely molecular structure-performance relationships for this new class of scale inhibitor. Additionally, hypotheses on the specific mechanisms by which these inhibitors function have been provided, showing why they are so successful at sulfide crystal growth retardation.

Static and dynamic test methods are described that accurately mimic formation of these scales in the field, in comparing the novel polymeric chemistry with the best-performing ‘standard’ scale inhibitors. Order of magnitude increases in performance over standard species are reported which represents a true step-change in the efficacy of sulfide scale inhibition.
The Challenges Associated with Reaction Products Left in Scale Inhibitor Species after Radical Polymerization
Authors: Wylde Jonathan J.
Published: February 2021

The use of polymeric scale inhibitors has been ubiquitously accepted by the oil and gas industry for many years. There are many benefits to the use of this type of chemistry that include aspects such as high performance, scale species selectivity, enhanced brine compatibility, favorable environmental properties and high thermal stability.

A very common way to manufacture polymeric scale inhibitors is via free radical polymerization. Here an initiator is used to propagate the generation of free radicals from a species, such as hydrogen peroxide. The initiator chemistry can be very varied and usually comprises different types of transition metal salts, hypophosphite or persulfate species. Different monomer units can be polymerized using different initiator and free radical species to yield the same polymer. However, subtle differences can result, including poly-dispersity, average molecular weight and different residual composition. The implications for the end user of the chemistry can be profound regarding performance differences in aspects such as detectability, compatibility, thermal stability and sometimes even scale inhibition and adsorption efficacy.

A case study has been presented where a very commonly used sulfonated copolymer species from four different sources was evaluated in a whole host of compatibility and performance tests. The different routes used different combinations of hydrogen peroxide and transition metal initiator or persulfate/hypophosphite combinations as the free radical source.

There were major differences seen in the compatibility of these products with different scale inhibitors and then in performance. The tests performed highlighted the differences that can occur between the different radical polymerization synthetic routes mentioned above.

The conclusions show that there are many benefits to being able to control the manufacturing process of scale inhibitor species in order to ensure the full composition is understood and can be quantified. The benefits to owning the supply chain are highlighted and lead to not only better control of quality and cost but, more importantly, to the overall risk reduction for the end user in the end use application.
Coupled Adsorption/Precipitation Tests with a Phosphonate Inhibitor and Carbonate Substrate
Authors: Thomas W.S. , Sorbie K.S. , Singleton M.A.
Published: February 2021

A series of static adsorption/precipitation tests has been carried out to examine the behaviour of Diethylenetriamine Penta Methylene Phosphonic (DETPMP), a commonly used commercial scale inhibitor (SI), when in contact with brine and calcium carbonate (CaCO3). These tests are carried out at pH 2 and pH 4 and at a range of DETPMP concentrations from 0ppm to 5000 ppm. In these tests, the addition of disaggregated CaCO3 to the brine/SI mixture was accompanied by a rise in the pH and a commensurate precipitation of a DETPMP_Ca complex. Apparent adsorption displayed a common 2:1 trend indicating that no adsorption took place, only precipitation. These results changed somewhat when selected divalents (Ca and Mg) were removed from the brine.
Pre-Production Deployed Scale Inhibition Treatments in Deep-Water, West Africa
Authors: Patterson D. , Williams W. , Jordan M. , Douglas R.
Published: February 2021

The injection of seawater into oil-bearing reservoirs in order to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulphate) to the injection and production wells during such operations has been much studied. The current deep-water subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way.

In a deepwater West African field the relatively small number of high-cost, highly productive wells, coupled with a high barium sulphate scaling tendency upon breakthrough of injection seawater meant not only was effective scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts have proven to be at sufficient risk to require early squeeze application.

To provide effective scale control in these wells at low water cuts, phosphonate-based inhibitors were applied as part of the acid perforation wash and overflush stages prior to frac packing operations. The deployment of this inhibitor proved effective in controlling barium sulphate scale formation during initial water production eliminating the need to scale squeeze the wells at low water cuts (<10% BS&W). To increase the volumes of scale inhibitor being deployed in the pre-production treatments and so extend the treatment lifetimes scale inhibitor was also added to the frac gel used to carry the frac sand.

This paper outlines the selection methods for the inhibitor chemical for application in frac fluids in terms of rheology, retention/release, formation damage and presents the chemical returns profile from the 5 wells treated (some treatments lasting > 300 days) along with monitoring methods utilized to confirm scale control in the wells treated.

Many similar fields are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.
New Insights on the Impact of High Temperature Conditions (176°C) on Carbonate and Sulphate Scale Dissolver Performance
Authors: Jordan Myles M. , Williams Helen , Linares-Samaniego Sandra , Frigo Dario M.
Published: February 2021

Scale-dissolver technology has been developed and applied with varying degrees of success over the past few years to remove carbonate and the more challenging sulphate/sulphide scales from production tubing and process equipment. It can often seem a much safer, more cost-effective remediation approach than physical removal, in particular, in the new generation of HP/HT fields, where any physical well intervention carries high risk, while the high temperatures would normally be beneficial in enhancing scale solubility and dissolution rate.

The current paper reports dissolution characterstics of three solvents for calcite, barite, celestite and anhydrite in the temperature range 85°C to 176° to verify their performance up to the very high temperatures of a specific HP/HT development. These solvents included a typical alkaline-pH chelant for sulphate scale, an organic-acid mixture for carbonate scales, and a novel neutral-pH chelant as a less corrosive solvent for carbonate scale removal. In some tests the liquid-to-solid ratiowasvaried to evaluate the impact of excess scale on solvent performance.

The performance against BaSO4 of the alkaline-pH chelant unexpectedly declines very significantly at 176°C relative to that observed at 85°C. Thermal instability was ruled out as the cause becausethe solvent showed very limited decline in performance when tested at 85°C after it had been thermally aged at 176°C. Performance at 176°C showed an initial rise followed by a decreasein aqueous barium ions, strongly indicating secondary re-precipitation of a barium-containing species at this temperature. In contrast, dissolution rates of carbonate scale by organic acid were greaterat the higher temperature, as would be expected. The novel neutral chelant showed a decline in calcite dissolution performance during the 176°C test but unlike the alkaline-pH chelant used for sulphate scale, this chelant showed degradation after thermal ageing and re-testing at 85°C.

The findings from this paper suggest that there is temperature limit above which effective removal of sulphate scales may not be feasible with the selected solvents due to re-precipitation of a secondary reaction product, while for carbonate removal the current neutral chelants tested have a thermal stability issue at 176°C. These findings need to be considered when evaluating the potential role of chemical remediation in the overall scale-control strategy for HP/HT fields.
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

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

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

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

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

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

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

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 >200, 000TDS) and high temperature (HT >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

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

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

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.
Constraining the Conditions of Scale Deposition in a Gas Condensate Well: A Case Study
Authors: McCartney R. A. , Duppenbecker SPE, S. , Cone R.
Published: February 2021

Field X is a gas condensate field where the wells produce primarily gas and a small amount of formation water mixed with condensation water (<19 Sm3/d per well). Unexpectedly, scale (aragonite, possibly with minor sulfate minerals) was identified in Well A during a routine PLT. To aid scale mitigation planning, the cause of scale deposition has been investigated using scale prediction software.

A wide variety of data and information has been used to constrain and verify the scale predictions and as a result they are consistent with the observed type, volume and location of scale, PLT results (inflow temperature, hydrocarbon flow profile), produced water and formation water Ca and Cl concentrations, and production data (hydrocarbon and total water rates). A novel method was developed to estimate the composition of formation water entering the well from produced water analyses (mixtures of condensation and formation water) and where produced water rates are available this can also be used to estimate the rate of flow of formation water into the well.

The results suggest that formation water enters the well at low rates (∼1m3) from the upper perforated zone (Formation 1) whilst water-saturated hydrocarbons enter from both the upper and lower zones (Formations 1 and 2). The formation water Cl concentration is between ∼5, 100 and ∼11, 000 mg/L and the Ca concentration may be between ∼121 and ∼177 mg/L. Partial evaporation of formation water (due to pressure decline and Joule-Thomson heating) as it enters the well causes scale deposition. The remaining formation water is produced along with water condensing from gas. An additional risk of total salt deposition in these wells was also identified.

This study has shown how a wide range of data can be used to constrain the conditions of scale deposition in such wells. The results of this study are being used to develop scale management plans for the field.
Test Method Development and Scale Inhibitor Evaluations for High-Salinity Brines in the Williston Basin
Authors: Lu Haiping , Haugen Chris , Garza Tim , Russek Jeffrey , Hughes Baker , Harbaugh Chad
Published: February 2021

In the Rocky Mountain region of the United States, high-salinity brines (total dissolved solids > 250, 000 mg/L) present during oil and gas production cause severe scale problems in the Williston Basin. The scales include not only calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, but also sodium chloride (halite). This paper presents the development of test methods and their corresponding testing results for scale inhibitor evaluations in the laboratory and their applications in the field for high-salinity brines.

It is well known that there is no effective test method for halite scale inhibitor laboratory testing due to the difficulty of controlling the amount of halite precipitation and reproducibility in the test. The evaluation of scale inhibitor performance was conducted by using a tube-blocking test and a static bottle test with synthetic high-salinity brines from the Williston Basin. Two sets of brines were designed, based on the field brine, and were tested with two methods. One set of brine was for halite scale inhibitor evaluation by mixing near-saturated NaCl synthetic brine with a highly concentrated brine of CaCl2·2H2O + NaCl. The second set of brine was designed to evaluate scale inhibitor performance on calcium carbonate, calcium sulfate, barium sulfate, and strontium sulfate by modified brines. Three types of scale inhibitors were used for the performance evaluations, including halite scale inhibitors, general scale inhibitors, and a multifunctional scale inhibitor. The lab test results showed the multifuntinal scale inhibitor exhibited good scale inhibition performance for both sets of scale testing. Successful scale inhibitor implementations in the field applications and case history are also presented in this paper.
Liquid Scale Inhibitors for Metallic-Crosslinked Gel Fracturing Systems
Authors: Yue Zhiwei , Fu Qiang , Lang Nancy , Fan Chunfang
Published: February 2021

Scale inhibitors are important additives in fracturing fluids to help prevent mineral scale depositions during hydraulic fracturing, shut-in, and flowback stages. The inhibition mechanisms rely heavily on the interactions of certain functional groups from the inhibitor molecules and the lattice metals on the scale crystal surface. In stimulation using crosslinked gel fluids based on metallic crosslinkers, such as zirconium (Zr), titanium (Ti), or aluminum (Al), these metals form strong covalent bonds with guar and guar derivatives and therefore significantly increase overall gel stability. When anionic liquid scale inhibitors are present, the crosslinker metals are susceptible to attack from scale inhibitors because of similar interactions, often resulting in lower viscosity and compromised fluid performance. For this reason, liquid scale inhibitors are usually pumped in prepads during many fracturing treatments. During these treatments, fracturing fluids from other stages and reservoirs that contact these fluids are not protected from scale deposition. Although this incompatibility issue is an important factor in designing fracturing fluid systems, the authors have not found sufficient prior literature providing valid solutions other than applications of time-released solid scale inhibitors.

This paper investigates the interferences of various types of liquid scale inhibitors on Zr-based crosslinkers. Their chemical compatibilities are evaluated in terms of crosslinked viscosity stability and scale inhibition efficiencies. Data presented in this paper indicate that two polymer-based liquid scale inhibitors can be added to selected Zr-crosslinked fluids with minimal impact on crosslinking performance. Scale inhibition efficiency can be maintained by adjusting the pumping flow rate to compensate for the effect of Zr-based crosslinkers.
Mechanisms, New Test Methodology and Environmentally Acceptable Inhibitors for Co-deposition of Zinc Sulfide and Calcium Carbonate Scales for High Temperature Application
Authors: Tortolano Christopher , Chen Tao , Chen Ping , Montgomerie Harry , Hagen Thomas , Benvie Ronald , Zou Lucy
Published: February 2021

Zinc sulfide (ZnS) is one of the notoriously exotic scales formed in the high temperature oil fields. Its formation can potentially cause severe scale issues by itself or combined with conventional CaCO3 scale. Limited publications are available on ZnS deposition/inhibition, let alone the combined ZnS and CaCO3 scales. The mechanisms of these scale interactions are still unknown.

The relatively small amount of ZnS precipitated that adheres to surfaces and its ‘soft’ scale characteristic make it difficult to test ZnS using traditional scale inhibitor evaluation test methods, especially at high temperature. A new methodology with modified dynamic loop test combining the traditional test coil and novel test filter system has been developed and allows evaluating ZnS and combined ZnS/CaCO3 at high temperature in the absence and in the presence of scale inhibitors.

Co-deposition of ZnS/CaCO3 and the interference between ZnS and CaCO3 have been studied at elevated temperature. The mechanisms have been addressed by both scale prediction and laboratory tests. Findings from this study show that ZnS dramatically accelerated CaCO3 formation within the test brine and made the scaling condition extremely harsh, even with a very small amount of ZnS present.

Several types of inhibitor chemistries were short listed for this study based on a previously published mechanism study to assess their ability to prevent ZnS and co-deposition of ZnS/CaCO3 at elevated temperature. Type-1 inhibitor is dispersion/nucleation, type-2 is nucleation/growth and type-3 has no inhibition function on ZnS. The test results conducted at 170°C agree well with the mechanism assumed by the previous mechanism study, and the inhibition mechanisms are reinforced. The minimum inhibitor concentration (MIC) of scale inhibitors has been evaluated for CaCO3 and co-deposition of ZnS/CaCO3 at 70°C and 170°C. The difference of MIC gives an indication of the negative effect that very small amounts of ZnS can have on the inhibition of co-deposition. The performance of environmentally acceptable inhibitors is also presented for this challenging environment.

This paper presents a comprehensive study of the challenge of ZnS and co-deposition of ZnS/CaCO3 under conditions similar to that of many of the current HT/HP field developments in the North Sea and recent developments in the Gulf of Mexico.
Lessons Learned from Production History Matching in Single Cell Numerical Models in an Integrated Asset Model
Authors: Noguera C.
Published: February 2021

Integrated Asset Modeling (IAM) approach1 is defined as simultaneously modeling the flow through the reservoir up the wellbore and through a surface network. Reservoir simulation history matching is one of the most complex and time consuming process, however, it ensures that the model developed is useful for forecasting and management decisions. By nature, an Integrated Asset Modeling model can be made up of hundreds of nodes, making it complex and difficult to manage if a proper methodology is not implemented to allow an effective history matching, especially when developing all the components of the IAM model.

The purpose of this paper is to share lessons learned from a methodology that allows the development of reservoir models via material balance, proper matching of wellbore models and wellbore tests; calibration of the surface network and ultimately, history matching of an Integrated Asset Model, following rigorous quality assurance and quality check procedures. Issues addressed include: characterization of the reservoir-wellbore system, knowledge of main drive mechanisms, aquifer uncertainty, tubing flow assessment.

The methodology enabled production history matching of 15 producing gas wells; ensuring that the IAM model developed is therefore a reliable forecasting tool. In addition, Simulation run time reduction was achieved by switching from a rate dependent constrained system to a pressure drop dependant system.

Production history matching should precede any numerical simulation study, as it provides useful knowledge of the properties and characteristics of the reservoir-wellbore-surface network, leaving little room for adjustments, which constitutes an excellent starting point for numerical models; hence an IAM approach represents basis for the construction and quality check of more rigorous multi cells numerical reservoir simulation models.
An Integrated Approach Using Geomechanics and Advanced Rock Characterization Techniques to Optimize Reservoir Productivity and Stimulation Design
Authors: Nguyen M. , Worku T. , Mitchell W.P. , Lakshmikantha M.R. , Hegazy M.
Published: February 2021

Accurate prediction of geomechanical rock properties is one of the main challenges to be overcome in E&P projects, in order to optimize well completion design and stimulation strategy. This is especially so in the early stages of a project, e.g the appraisal phase. In the recent years, Scratch Testing has become an emerging geomechanical characterization technique that is used to determine the mechanical properties of the rock. With this method, a groove of fixed depth (typically less than 1 mm) is scratched on the rock surface. The forces acting on the cutter are recorded at a high sampling rate (about 10 samples per millimeter), with high precision and resolution (about 1 Newton). This scratch test data is then used to characterize the length of heterogeneity of the rock, and to generate the geomechanical properties profile (rock strength, friction angle). Presently, such valuable information is only partially integrated with petrophysical and geological data. A series of Scratch tests are performed on different rock samples and types to create a continuous rock strength profile, which is then integrated with sedimentology, core analysis and wireline logs. This data assimilation led to the development of, a new technique to assist in the extrapolation of rock strength in un-cored intervals/wells. In this paper, the developed workflow will be further elaborated, along with its results and applications to support the design of a fit for purpose well completion and stimulation strategy, which is a key component in the field development planning phase of an E&P project.