SCALE FORMATION IN WELLS DRILLED ON

CARBONATE RESERVOIRS DEVELOPED

THROUGH WATERFLOOD MECHANISM

Gustavo Pereira

Projeto de Graduação submetido ao Corpo

Docente do Curso de Engenharia de Petróleo

da Escola Politécnica da Universidade Federal

do Rio de Janeiro como parte integrante dos

requisitos necessários à obtenção do título de

Engenheiro de Petróleo.

Orientadores: Santiago Gabriel Drexler e Paulo Couto.

Rio de Janeiro

Março de 2020

iii

Pereira, Gustavo Medeiros

Scale Formation in Wells Drilled on Carbonate Reservoirs

Developed Through Waterflood Mechanism / Gustavo

Medeiros Pereira. – Rio de Janeiro: UFRJ/ Escola

Politécnica, 2020.

IX, 42 p.: il.; 29,7 cm.

Orientadores: Santiago Gabriel Drexler e Paulo

Couto.

Projeto de Graduação – UFRJ/ Escola Politécnica/

Curso de Engenharia do Petróleo, 2020.

Referências Bibliográficas: p. 40.

1. Incrustração Salina. 2. Garantia de Escoamento. 3.

Carbonato de Cálcio. 4.Sulfato de Bário. 5. Reservatórios

Carbonáticos. I. Drexler, Santiago Gabriel e Couto,

Paulo. II. Universidade Federal do Rio de Janeiro, Escola

Politécnica, Curso de Engenharia do Petróleo. III. Scale

Formation in Wells Drilled on Carbonate Reservoirs

l d h h fl d h i

iv

“What matters the most is how well you

walk through the fire.”

v

AGRADECIMENTOS

Agradeço aos meus pais, Gisele Matildes Medeiros e João Batista Pereira, por

apoiarem as minhas escolhas e permitirem que eu seguisse meu sonho. Pela

educação e pelo privilégio de ter tido oportunidade de acesso a uma faculdade pública.

Agradeço ao meu parceiro, Felipe Zanetti Comério, por ter me suportado neste

(e em dezenas de outros) desafio acadêmico. Por ter me ensinado muito ao me

mostrar seus pensamentos e compartilhar tantas experiências comigo. Por todo o

amor e por toda a força. Independente do amanhã, vivemos o hoje.

Agradeço aos meus incríveis amigos, que contribuíram para a minha formação

acadêmica, pessoal e profissional, me acompanhando nos anos de Fundão. À família

do 203, meu alicerce ao longo desses anos em terras cariocas: Thayná Gonçalves,

minha maior parceira nos melhores e piores momentos; Willian Velasco, o primeiro

amigo que tive em que me vi, e Vinícius Felipe, que embarcou comigo na primeira

colossal mudança de nossas vidas. Ao amigo com o coração mais dourado que já vi,

Oziel Baiense. Ao super-Grupo 3, Matheus Gonzaga e Marco Tulio Portella, sem o

qual minha trajetória acadêmica teria sido catastroficamente diferente. À Marília

Cizeski e Rafaela de Pieri, pelo amor nutrido, mesmo a distância, pelos desabafos,

conselhos e por compartilharem a dor dessa saudade comigo. E todos os demais que

fizeram parte dessa trajetória.

Agradeço à professora Rosemarie Bröker Bone, que abriu seu laboratório para

receber alunos do país inteiro, nos ensinando não só economia e petróleo, mas

preciosas lições de vida. Por ter sido quase uma mãe sulista em terras cariocas. E por

ter lutado pela excelência do curso de Engenharia de Petróleo da Universidade

Federal do Rio de Janeiro, e por seus alunos, por décadas.

Agradeço ao coorientador Paulo Couto, pelo apoio na monografia, por ser a

referência de uma legião de engenheiros quando se trata de Engenharia de

Reservatórios, e pelos esforços hercúleos em prol do curso de Engenharia de Petróleo

e de seus alunos.

Agradeço ao meu orientador, Santiago Gabriel Drexler, que acreditou neste

trabalho e esteve disponível em todos os momentos para suporte. Pelas ideias de

melhoria, pela paciência e pelo esforço, mesmo em épocas ocupadas. E por suas

aulas ao longo do curso, de preparo, pontualidade e conhecimento exemplares.

Agradeço especialmente aqueles que impactaram de uma maneira inigualável

minha trajetória profissional. À Shell Brasil, especialmente João Baima e Philip

Bogaert, pelos ensinamentos, pela amizade e por acreditarem em meu potencial como

poucos. Vocês me apresentaram ao tema e, sem vocês, esse trabalho não existiria. À

vi

Tatiana Hallak, pela mentoria e pelos conselhos. À rede TrueColors, Luiz Oliveira,

Yasmin Reis e Ruan Melandres, por terem construído um lugar onde as pessoas são

livres para serem quem são e, só assim, florescerem pessoal e profissionalmente.

Por fim, agradeço à Universidade Federal do Rio de Janeiro, a Universidade do

Brasil, por ter se tornado minha segunda casa nesses últimos anos. Por não ter me

ensinado apenas uma engenharia de qualidade inigualável, mas sobre a vida e a

sociedade. Espero um dia poder retribuir a honra de ter me graduado em uma

universidade de tamanha excelência e história.

vii

Resumo do Projeto de Graduação apresentado à Escola Politécnica/ UFRJ como

parte dos requisitos necessários para a obtenção do grau de Engenheiro de

Petróleo.

FORMAÇÃO DE INCRUSTAÇÕES SALINAS EM POÇOS PERFURADOS EM

RESERVATÓRIOS CARBONÁTICOS DESENVOLVIDOS PELO MECANISMO DE

INJEÇÃO DE ÁGUA

Gustavo Medeiros Pereira

Março, 2020

Orientadores: Santiago Gabriel Drexler e Paulo Couto.

Curso: Engenharia de Petróleo

A incrustação de sais inorgânicos no sistema de produção de óleo e gás é um dos

problemas mais comuns de garantia de escoamento, estabilidade e otimização da

produção, principalmente em campos desenvolvidos através da injeção de água

(waterflood). Este estudo visa demonstrar o uso de uma modelagem iônica

realizada no software OLI ScaleChem, somada a uma ferramenta de visualização,

na previsão de deposições no poço e seus arredores. A ferramenta desenvolvida

permite a análise de dezenas de poços simultâneamente, simplificando as

análises técnicas requeridas para a tomada de decisão e tornando mais fácil a

escolha dos poços críticos. Ela também permite a inferência dos tipos de sais

depositados no poço e o melhor plano de tratamento do mesmo, para aumentar a

produção. Colaborando com a análise desenvolvida, este estudo trará uma revisão

bibliográfica do tema e de conceitos químicos a ele relacionados. Por fim, a

ferramenta desenvolvida é utilizada em um estudo de caso de um poço em

reservatório carbonático desenvolvido pelo mecanismo de waterflood. Ela aponta

para a deposição de sulfato de bário e carbonato de cálcio, o que foi corroborado

pelas técnicas usualmente utilizadas na indústria, e considerado para o tratamento

do poço. Tal tratamento permitiu que a produtividade do poço dobrasse, o que

confirma a importância deste estudo, já que permite simplificar o processo de

melhoria na produção de maneira mais rápida e barata.

Palavras-chave: incrustação salina, garantia de escoamento, carbonato de cálcio,

sulfato de bário, reservatórios carbonáticos.

viii

Abstract of Undergraduate Project presented to POLI/UFRJ as a partial fulfillment

of the requirements for the degree of Engineer.

SCALE FORMATION IN WELLS DRILLED ON CARBONATE RESERVOIRS DEVELOPED THROUGH WATERFLOOD MECHANISM

Gustavo Medeiros Pereira

March, 2020

Advisors: Santiago Gabriel Drexler and Paulo Couto.

Course: Petroleum Engineering.

The deposition of inorganic salts along oil and gas production system is one of the

main issues for flow assurance and production stability and optimization, especially

in fields developed through the waterflood mechanism. This study aims to

demonstrate the use of an ionic model developed in OLI ScaleChem, aligned with

a visualization tool, on predicting the depositions on the well and near-wellbore

area. The developed tool allows for the analysis of dozens of wells simultaneously,

simplifying the required technical analysis that impact directly the decision-making

process by making it easier to define the most critical wells. It also allows the

inference of the types of salts deposited downhole and, therefore, an improved

plan for the treatment and removal of it, which will increase the production.

Supporting the developed analysis, the study carries out a revision of current

literature on the main scale formation mechanisms and most common deposited

salts in the industry, as well as the necessary chemistry concepts. Finally, the

solution presented is utilized on a case study of a well in an uncharacterized

carbonate reservoir developed through waterflood. It points to barium sulphate and

calcium carbonate deposition, which is corroborated by the industry’s usual

diagnostic methods and taken into consideration in the development of a treatment

plan. After the plan was executed, the productivity of the well doubled, which

indicates the importance of this study that can simplify the process of production

improvement in a quicker and cheaper manner.

Keywords: salt deposition, flow assurance, calcium carbonate, barium sulfate,

carbonate reservoirs.

ix

CONTENTS

1. INTRODUCTION .......................................................................................................... 11

1.1. MOTIVATION ............................................................................................................... 11

1.2. OBJECTIVE OF THIS STUDY .......................................................................................... 13

1.3. STRUCTURE OF THE TEXT ............................................................................................ 13

2. THEORETICAL FRAMEWORK ....................................................................................... 15

2.1. SCALE OVERVIEW ........................................................................................................ 15

2.1.1. Scale Definition and Formation ........................................................................... 15

2.1.2. Most Common Types of Oilfield Scale ................................................................ 16

2.1.3. Operational Problems due to Scale ..................................................................... 18

2.1.4. Scale Treatment and Prevention ......................................................................... 19

2.2. FUNDAMENTAL CONCEPTS FOR IONIC ANALYSIS ....................................................... 20

2.2.1. Equilibrium Constants and Activity ..................................................................... 20

2.2.2. Solubility .............................................................................................................. 21

2.2.3. pH Dependency ................................................................................................... 23

2.2.4. Supersaturation and Saturation Ratio ................................................................. 23

3. METHODOLOGY ............................................................................................................. 24

3.1. SOFTWARE INFORMATION .......................................................................................... 24

3.1.1. OLI Analyzer Studio ............................................................................................. 24

3.1.2. TIBCOTM Spotfire® ................................................................................................ 25

3.1.3. Data Gathering, Modelling and Plotting ............................................................. 25

4. RESULTS AND DISCUSSIONS ........................................................................................ 28

4.1. Case Study ................................................................................................................... 28

4.2. OLI Modelling and Required Calculations ................................................................... 30

4.3. Spotfire Plots and Analyses ......................................................................................... 34

4.3.1. Calcium Sulphate – Anhydrite and Gypsum ........................................................ 34

4.3.2. Barium Sulphate and Strontium Sulphate ........................................................... 36

4.3.3. Calcium Carbonate .............................................................................................. 38

4.4. Treatment, Prevention and Results ............................................................................ 38

5. CONCLUSIONS ............................................................................................................... 40

BIBLIOGRAPHY .................................................................................................................. 42

11

1. INTRODUCTION

1.1. MOTIVATION

Energy demand is expected to increase over the years as the world

develops economically and more countries have a better life quality for their

citizens, which can be seen by the average annual increase in energy consumption

worldwide of 1.5% from 2007 to 2017 (BP, 2019). In 2018 only, primary energy

consumption increased by 2.9%, oil demand growing by 1.5% and natural gas in

5.3%, a volumetric record-high (BP, 2019). During primary recovery of oil and gas

reservoirs, typically only 5-10% of initial hydrocarbons are produced (NASERI et

al., 2014), which indicates the need for secondary and tertiary recovery techniques

for a more efficient oil and gas production. Waterflood, or water injection, is one of

the most common secondary recovery techniques (NASERI et al., 2014).

In the case of waterflooded reservoirs, geochemical processes between

injection water, formation water and rock occur, generating an increase of the ionic

concentration of the water in place, contributing to the precipitation of salts from the

solution. The deposition of inorganic salts such as calcium carbonate and barium

sulphate, also known as scale, can damage the formation around an oil and gas

well, leading to a decrease in production, as well as causing equipment failure or

loss of efficiency when happening in other parts of the system (KHORMALI et al.,

2016). BP estimates that they lose 4 million barrels of oil annually due to scale in

the North Sea and that 20% of their well losses are due to scale damage

(GRAHAM et. al, 2002). This is particularly relevant for offshore fields in which

seawater containing sulfate ions is injected, causing potential chemical

incompatibility with formation brine (NASERI et al., 2015). The product of the

mixture of injection and formation water is an unstable, supersaturated, brine,

which precipitates and limits the oil and gas production by decreasing the flow area

of the rock surrounding the well, the perforated intervals, the well itself and even

production facilities, leading to lower gains and higher costs with scale removal

operations (NASERI et al., 2015).

Calcium sulfate (CaSO4), calcium carbonate (CaCO3), barium sulfate

(BaSO4), strontium sulphate (SrSO4) and iron compounds are the most common

oilfield scales (MOGHADASI et. al, 2003), but the control of the inorganic salt

formation is still complicated due to the complex reservoir fluid composition, the

uncertainties of key parameters when choosing a treatment and the higher costs.

12

Different conditions are required for scale precipitation and its intensity can

vary depending on these conditions. First, a high concentration of salt-forming ions

in the produced brine is essential. Pressure and temperature are also key to the

phenomenon, and smaller chemical characteristics such as the presence of carbon

dioxide (CO2) in the water or the brine undergoing evaporation can lead to it (AZIZ

et al., 2011). Since pH is characterized by the equilibrium condition between the

liquid, solid and gaseous phases, it speaks to the overall equilibrium of the brine

and therefore also impacts scale formation. Saturation index and scaling tendency

are usually taken as an indication of scale formation, but only allows to access

qualitatively the ability of the water to precipitate or dissolve the salt (MOGHADASI

et al., 2003).

Scale treatment can be done in several different ways, when inside pipes,

mechanical methods such as explosions that will cause shock vibrations to the pipe

and break off brittle scales, and milling, impact and jet blasting techniques are

commonly used (NERGAARD et. al, 2010). For wells, perforated intervals and

treatment plants, chemical methods are preferred, usually acid treatments or

chelating agents. As these methods tend to be very expensive and as the salt

builds up the oil production decreases, scale inhibition, which will hinder the growth

of the deposition or prevent it from forming, is a common process for wells that

have a high scale tendency. There are thousands of different scale inhibitors, but

most of them are phosphate compounds (CRABTREE et. al, 1999) and they can

be injected all over the system, in the topsides/process plant, in the wellhead, in

chemical mandrels inside the well and even in the rock surrounding the well during

campaigns called scale squeezes, adhering the chemicals to the geological

surface and releasing them through time as the reservoir liquid is produced.

A significant part of scale control and management concentrates on

understanding the conditions of its formation, which allows for an improved

inhibition and remediation. But time is of essence, as any salt formation implicates

production decrease, and the resources to simulate scaling tendencies for every

single producer well are not always available. Previous studies have been able to

qualitatively predict the salt formation and scaling intensity (AMIRI et al., 2013), but

the process to do so is usually very laborious and burdensome, requiring

remodeling for every different water sample or well. The model presented in this

study allows for a simulation to be done only once per reservoir by assuming that

the conditions of formation and injected water are similar throughout the whole

field. As output, it allows the engineer to keep track of a well’s tendency to deposit

13

different types of salt, recognize changes in behavior through time, pointing out

which are the wells that really need a more detailed modelling and treatment plan.

The limitations are that it works only as a qualitative method, not replacing a

meticulous model that can calculate volumes of chemicals to be injected, for

example, but only pointing out which are the wells that will require such. It

increases the overall knowledge of the producing fields and wells, empowering

proactive technical monitoring of the producing asset and preventing scale issues

to escalate further, leading to decreases in treatment costs and the possibilities of

acting sooner to avoid further damage to the producing wells.

1.2. OBJECTIVE OF THIS STUDY

This study aims to provide a new tool for scale management and

monitoring, detailing the development process and the applicability with a real

example, a case study. The data comes from a producer well drilled in a carbonate

reservoir developed through a secondary recovery mechanism of waterflood and,

therefore, additional conclusions might emerge throughout the process, such as

inferring the most common scale types for systems in similar conditions.

It also aims to carry a literature review of the scale deposition, its formation

mechanisms, most common types and characteristics, operational problems,

safety issues, treatments and prevention, also introducing chemical and petroleum

engineering concepts related to the issue, to serve as future reference for studies

and papers on the topic.

1.3. STRUCTURE OF THE TEXT

This study is divided in six chapters with the following structure:

• CHAPTER I: INTRODUCTION – This chapter establishes the

context, motivation and objective of this study, introducing some key

topics for the following chapters.

• CHAPTER II: THEORETICAL FRAMEWORK – This chapter

presents an overview of the current status of scientific literature on

scaling, detailing the issue, its causes, impacts and treatments, and

introducing chemical and petroleum engineering concepts that serve

as a foundation for the comprehension of the issue.

14

• CHAPTER III: METHODOLOGY – This chapter details the

methodology used in this study, covering the computational

programs, functions and modelling methods utilized.

• CHAPTER IV: RESULTS AND DISCUSSIONS – This chapter

presents the results obtained using the methodology described in

the previous chapter, applying the developed model to a case study

and analyzing the results of it (i.e. if scale is an issue for the

presented well and which sort of salt needs to be treated and/or

prevented).

• CHAPTER V: CONCLUSIONS – This chapter presents a short

summary of what was presented throughout the study and an

overview of what were the outcomes of the model in the case study,

highlighting what the present writing adds to the scientific

community and the Oil and Gas Industry.

• BIBLIOGRAPHY – This chapter contains the references quoted

throughout the study, that served as a foundation for it.

15

2. THEORETICAL FRAMEWORK

The scope of this chapter is to give an overview on important topics related to

the case study that will be explained in further chapters and the physical and chemical

concepts that rule scale deposition. It is divided in two sections that discuss the theory

behind the phenomenon of interest in this study. First, a review of scale formation itself,

the mechanisms that rule it and ways to prevent or remediate its impacts, including a

review on the most common scale types for oilfield operations. Second, the chemical

definitions behind scale formation, crucial for the understanding of the developed

model for predicting scale deposition presented in Chapter 4, including activity,

solubility and saturation ratio.

2.1. SCALE OVERVIEW

2.1.1. Scale Definition and Formation

Mineral scales are inorganic crystalline deposits, hard and adherent, that

precipitate from a brine solution (HINRICHSEN, 1998) and, on the issue that this study

follows on, this assembly of deposits can occur in the reservoir, perforation interval,

well bore, valves and in the surface process system (TUNGESVIK, 2013). Scale

formation is possible whenever an oil producer well starts producing water, or an

injector uses water as its main fluid, and the greater the volume of water involved, the

greater the potential volume of scale deposition (TUNGESVIK, 2013). It can restrict the

flowrate in any part of the system it deposits and hinder the operations of well

intervention by making it harder to access different parts of the well and damage

equipment such as valves and gas lift mandrels (TUNGESVIK, 2013).

The formation of scale depends on parameters such as pressure, temperature,

pH, degree of agitation and turbulence during the formation of crystals, size and

number of seed crystals and degree of super-saturation (TUNGESVIK, 2013). Flow

velocity, presence of impurities and carbon dioxide are also important, especially in oil

field fluids (MACADAM AND JARVIS, 2015). To form it, not only a shift in these

parameters leading to a condition of supersaturation is required, but a sub particle or

ion cluster of several individual scaling ions is required. This process is called

nucleation. It can be named homogenous nucleation if the scale growth starts in a

supersaturated solution and heterogeneous nucleation if the first crystals deposit on

substrates like metallic surfaces and sand grains (TUNGESVIK, 2013).

16

There are three main mechanisms of scale formation, each one more critical to

a different part of the production system: autoscaling, incompatible mixing and

evaporation. Autoscaling or self-scaling happens when the produced/reservoir water

goes through a change in pressure/temperature while being produced and, therefore,

this mechanism is critical for heat exchangers and pressure vessels. At higher

pressures and temperatures, mineral solubility is usually higher, i.e. lower probability of

deposition, but there are a few exceptions, such as Calcium Carbonate, that has a

lower solubility at higher temperatures. Incompatible mixing related depositions occur

when two chemically incompatible waters such as injected seawater and formation

water get mixed downhole, making the resultant brine oversaturated with scale

components. In this example, untreated seawater has a high content of sulphate and

formation water of calcium and barium, leading to a precipitation of sulphate scales

such as barium sulphate and calcium sulphate. The evaporation mechanism consists in

increasing the salt concentration above the solubility limit through the evaporation of

the hot brine phase due to an expansion of the hydrocarbon gas caused by pressure

drops on the system. Most common salt formed through this mechanism is halite scale

on high temperature, high pressure, wells (TUNGESVIK, 2013).

2.1.2. Most Common Types of Oilfield Scale

The most common scale types to be encountered in an oilfield and the critical

parameters that rule their deposition are stated in Table 2.1. They can be fairly divided

by physical and chemical properties in carbonate-based scales and sulphate-based

scales.

17

Table 2.1 Most common oil well scale deposits and the variables that influence

their deposition. Source: Moghadasi et. al, 2003.

Carbonate scaling may form during the production of formation water or when

re-injecting produced water, especially in systems containing carbon dioxide (CO2),

calcium and magnesium. Calcium carbonate is the most common one and it requires

calcium ions, bicarbonate and/or carbonate ions, and its likeliness is related to the

existence of carbonate reservoirs or and calcite-cemented sandstone reservoirs, where

the reservoir water is usually rich in calcium ions. The most common place for

carbonate scales deposition is near the downhole safety valves, upper completions and

in the surface facilities (TUNGESVIK, 2013). They are more likely to form in pressure

drops (due to the release of CO2 from solution into gas phase), increased pH, higher

temperatures and lower concentrations of Na+ and Cl-, the latter being related to the

ionic strength of the calcium carbonate ion.

Sulphate scales are usually formed when formation water and injection water

mix, as formation water is rich in barium, strontium and calcium ions, while seawater

has a high concentration of sulphate ions. The degree of precipitation and deposition

will vary over the field lifetime, depending on the water production rates and the fraction

of seawater in the produced water (TUNGESVIK, 2013). Sulphate scaling has little to

18

no dependence on pH and are more likely to form on lower temperatures, usually

happening in the location where the mixing happens, such as the surface water

injection facility, in injection wells in the point where injected water mixes with formation

water, downhole of the reservoir and production well, in manifolds and topsides

facilities where different produced fluids are comingled and in final disposal wells

(TUNGESVIK, 2013), as per Figure 2.1.

Figure 2.1 Possible sulphate scale deposition locations. Source: Tungesvik,

2013.

2.1.3. Operational Problems due to Scale

Scaling can lead to several issues in Oil and Gas production system, especially

in heating/cooling, desalination, steam generators, boilers, cooling towers, pipes,

tubing and all other equipment used in water intensive processes. It might even impair

the overall process, increasing the cost of production by increasing the maintenance

costs (MACADAM AND JARVIS, 2015). As explained before, the severity of the

problem will depend on the water composition, volume and operational conditions,

possibly taking weeks, months or years for the deposit to be significant.

Main deferment and cost increasing causes are the reduction in flow and heat

transfer, additional maintenance or breaking of equipment and increased energy losses

and power consumption. Table 2.1 compares the thermal conductivity of the salts in

comparison to copper and allows for an idea of how much the efficiency of the heat

19

exchanging equipment might fall, as the thermal conductivity of Calcium Carbonate is

almost 140 times lower than of copper.

On a well level, these deposits can block pore throats in the near-wellbore

region or in the well itself, causing formation damage and loss of productivity. It can

lead to severe safety issues, blocking pipes, causing the failure of safety critical

systems and valves and even by the kind of deposit itself: Naturally Occurring

Radioactive Material (NORM) scale is a deposition that usually contains isotopes of

radium and decay products, being a occupational hazard for ingestion and inhalation

risks, especially when removed and turned into finer particles (BETTS S.H., 2004).

Scale depositions are a big problem in offshore fields, for sulphate scale formation due

to mixing of incompatible waters is common, and for hydraulic fracking, due to the

production of hypersaline waters, and as oil exploration moves to more extreme

environments with higher pressures, temperatures and salinities, these problems will

become more frequent.

2.1.4. Scale Treatment and Prevention

One of the most common scale control strategies is the modification of the

injected fluid, as seawater is still the main injected fluid in waterflood offshore fields, for

its availability and low cost, but it contains a high sulphate concentration, which leads

to sulphate-based depositions. A possible and commonly applied solution is to treat it

through nano-filtration, in a process called desulfation, but to concentrations that are

still relatively high and do not extinguish the possibility of scale deposition (ARAY AND

DUARTE, 2010). Another possibility is the change in water volumes and mixes, by

aligning wells that produce waters that are ionically different to separate production

systems/vessels, isolation of the water producing intervals/zones inside the well

through intervention or Intelligent Completion Valves actuation, subsea separation and

reinjection systems that keep the produced water from reaching locations on the

system where pressure and temperature are critical.

There are also several techniques of scale removal, that need to do no harm to

the production system (pipes, well and nearby formation) and will have its efficiency

related to the amount of scale deposited and the type of deposition, including its

physical composition and texture (ARAY AND DUARTE, 2010). Mechanical removal

consists in displacing tools through the pipes, tubing and perforations, varying from

explosives that will generate a great amount of energy and displace the deposition from

the surface it is adhered to, to the usage of drilling bits and impact hammers. They

have a higher cost but are more efficient for severe depositions and mixed-type scale

20

(coprecipitation of a different salt with the main one). Chemical removal has a lower

cost and is usually the first method at hand, especially when the scale is not easily

reachable, such as when inside the well perforations, being very effective for

carbonates, as they are very soluble in hydrochloric acid, as stated in Equation 2.1.

CaC03 + 2HCl ↔ CaCl2 + C02 + H20 (2.1)

Sulphates are not broken in acid, but by products containing chelators, agents

that break the scale by isolating the metal ions (Ca2+, Ba2+, Sr2+, etc.), keeping them

from reacting and forming the salt. Chelators are also commonly used after acid

treatments on carbonate depositions to keep the byproducts of the acid treatments of

starting a new scale deposition reaction.

There are also several prevention methods to keep scale from forming. Injecting

water in the system frequently can be a good choice if the deposited salt is Halite, but

there are thousands of inhibitors that can be injected in different points of the system,

from the topsides to inside the tubing in chemical injection mandrels, most of them

prevent scale growth by inhibiting nucleation, but even inhibited systems still have a

design life and limit of ions saturation in the brine (ARAY AND DUARTE, 2010). Wells

that have a higher tendency for scale are commonly designed for constant chemical

injection, be it through the wellhead or downhole, in injection mandrels. It is also usual

to perform operations called scale squeezes, in which the inhibitor is injected through

the entire system down to the reservoir near wellbore, where the chemical adheres to

the rock, being released as production fluids pass through it and protecting the entire

well and perforated intervals.

2.2. FUNDAMENTAL CONCEPTS FOR IONIC ANALYSIS

2.2.1. Equilibrium Constants and Activity

Chemical equilibrium is a dynamic state in which two or more opposing

reactions take place at the same time and rate (FRENIER AND ZIAUDDIN, 2008).

Once a closed system reaches this point, the chemical composition of the system does

not change and is, therefore, independent of time. Equilibrium constants are values

used to relate the amounts of reactants and products of a system in equilibrium. In a

simple reaction with reactants A and B and products C and D, for example, for which

the stoichiometric reaction is given by Equation 2.2, if the system is ideal, the

equilibrium constant Keq could be expressed in terms of concentration by Equation 2.3.

21

aA + bB ↔ cC + dD (2.2)

𝐾𝐾𝑒𝑒𝑒𝑒 = [C]𝑐𝑐[D]𝑑𝑑

[A]𝑎𝑎[B]𝑏𝑏 (2.3)

The equilibrium constant changes with pressure and temperature but in real,

non-ideal, solutions, especially the ones that are being cited in this study for their high

ionic concentrations, one ion is affected by other ions in the solution and the

equilibrium constants of these systems need to be expressed in terms of a species

activity, not concentration, which accounts for the other ions in the solution and can be

thought as an effective concentration of the species in solution (FRENIER AND

ZIAUDDIN, 2008), as per Equation 2.4.

𝐾𝐾𝑒𝑒𝑒𝑒 = {C}𝑐𝑐{D}𝑑𝑑

{A}𝑎𝑎{B}𝑏𝑏 (2.4)

2.2.2. Solubility

The concept of equilibrium constants aforementioned is useful when explaining

an important concept in the study of scale deposition, which is the idea of solubility of a

salt in water. Solubility is defined as the limiting amount of solute that can dissolve in a

solvent under a given set of physical conditions (RAWAHI et. al, 2017). In that set of

conditions, especially pressure and temperature as mentioned in the previous

chapters, while solute is in contact with solvent, dissolution occurs until the solution

reaches a state where the amount of solute dissolved is so high that the reverse

process starts taking place and the dissolved species starts going back to the previous

state, as a solute, in a process called precipitation. When in equilibrium, dissolution and

precipitation occur at the same rate, the amount of dissolved solute in the fixed solvent

volume remains the same and the mixture is called a saturated solution. Solutions that

contain less than this maximum are called undersaturated and the ones that contain a

higher concentration, possible due to the lack of initiation of the chemical reaction of

deposition for no seed crystals or surfaces exist or change in one of the previous

conditions (P, T, concentration…), are supersaturated.

As the solubility of a solute can be seen as the maximum concentration of

solute that can be dissolved in the solution under the given set of conditions (pressure,

temperature and concentration of other species in the solution). It is the equilibrium

constant for the reaction of salt dissolution. The equations exemplified for Calcium

Sulphate can be seen below in Equation 2.5, for the deposition reaction, and 2.6, for

the Solubility Product Ksp, being the brackets representative of the activity of the ion

22

and the activity of a pure solid equal to one, by definition. A low solubility product

means that little salt will be dissolved in water and precipitation is easier.

CaSO4 (s) ↔ Ca2+ (aq) + SO42- (aq) (2.5)

Ksp = {Ca2+}{SO42-} (2.6)

As with the equilibrium constant, when the temperature, pressure or

concentration of a solvent is changed, the solubility may increase, decrease, or remain

constant depending on the nature of the system. Exothermic processes have a

decrease in solubility with increased temperatures, endothermic processes have an

increase in solubility at higher temperatures. Figure 2.2 shows the solubility of common

oilfield scales and this correlation can be seen, as the deposition of calcium carbonate

is an exothermic process and barium sulphate has an endothermic one.

Figure 2.2 Solubility at different temperatures for common scales. Source:

Rawahi et. al, 2017.

23

2.2.3. pH Dependency

The formation of scale can also vary depending on the pH of the solution. For

calcium carbonate, the carbonate ion can attract a proton from water, generating in a

higher pH but, if lowered by the addition of acid, the equilibrium is shifted to the

dissolution of calcium carbonate into carbon dioxide and calcium anions. The amount

of CO2 present in the water affects the pH of the water and the solubility of calcium

carbonate, especially because, as it leaves the solution for the gas phase throughout

the production system due to the decrease in pressure, the pH of the brine rises. It

does not matter what causes the acidity or alkalinity of the water: the lower the pH, the

less likely is CaCO3 precipitation and vice versa. Sulphates, on the other hand, do not

usually require extensive knowledge on the chemical reactions within the brine and

CO2 on the gas phase, as they are not very impacted by changes in pH. Calcium

carbonate precipitation is possibly a big problem for carbonate reservoirs, where the

formation water is likely to be saturated with calcium carbonate under reservoir

conditions, where temperature can be as high as 200°C and the pressure up to 30 MPa

(RAWAHI et. al, 2017).

2.2.4. Supersaturation and Saturation Ratio

The degree of supersaturation of a solution can be quantified by the Saturation

Ratio (SR) as per Equation 2.7, where MZ+ is the cation (Ca2+ for example) and XZ- is

the anion (CO32-) and Ksp is the solubility product. If the saturation ratio equals 1, the

solution is saturated and in dynamic equilibrium and both precipitation and dissolution

are occurring simultaneously and at the same rate. When the saturation ratio is

smaller, the solution is undersaturated and precipitation will not occur. Conversely, a

SR greater than that means that the solution is oversaturated and precipitation of the

salts may occur (TUNGESVIK, 2013).

𝑆𝑆𝑆𝑆 = [M𝑍𝑍+][X𝑍𝑍−]𝐾𝐾𝑠𝑠𝑠𝑠

(2.7)

However, the actual deposition of scale will depend on the kinetics of the

precipitation reaction, as some salts do not start spontaneous precipitation even if they

are many hundred times super-saturated (TUNGESVIK, 2013), i.e. with SR bigger than

100. Furthermore, scale inhibitors, already introduced, can suppress the deposition by

interfering with crystal growth or nucleation.

24

3. METHODOLOGY

This chapter presents a summary of the methods and computational programs

utilized in the development of this study. It elaborates on the origin of the real field data

utilized and the modelling processes that it goes through for the generation of the

activity plots and saturation curves. Formation water, injection water and produced

water from random daily operations in the field are the key datasets to generate the

model and, as they vary between different fields and models, will be presented with

more detail only in the case study of Chapter 4.

The ionic activities and saturation curves were modelled using the software OLI

Studio (OLI Systems Inc.) from the ionic composition of the brines mentioned above,

CO2 concentration and pressure and temperature at the point of the system that is of

interest as input parameters. TIBCO Spotfire was utilized for generating the activity

plots, which is further detailed in Section 3.1.2.

3.1. SOFTWARE INFORMATION

3.1.1. OLI Analyzer Studio

OLI Analyzer Studio is the software that has stablished OLI Systems as the

world leader in simulating aqueous-based chemical systems (OLI Systems Inc, 2011).

It has the thermodynamic framework to calculate physical and chemical properties of

multi-phase aqueous-based systems in an enormous range of temperatures, pressures

and concentrations. ScaleChem is a subsystem in analyzer studio that allows the user

to calculate brines and reactions tailored for oil-field applications, including surface and

subsurface scale prediction, saturation profiles and water mixing. It can reconciliate the

sampled data so that the negative and positive ions balance each other, correcting

laboratory data for concentrations and even pH. The basis for the Studio is called OLI

Engine and it is composed by Solvers and Databanks. OLI Databank stores its own

coefficients for predicting thermodynamic and physical properties of the brine,

applicable for 80 inorganic elements of the periodic table and their associated aqueous

species, as well as 8000 organic species, and therefore most brines can be accurately

modeled.

For the input formation and injected water ionic composition, the model chosen

by OLI ScaleChem was the Mixed Solvent Electrolyte (MSE), which consists in a

framework capable of reproducing speciation, chemical and phase equilibria,

25

applicable to water-salt systems in the full range of concentrations of the Databank

(OLI Systems Inc. 2011). The equation of state utilized by the software is the HKF

(Helgeson-Kirkham-Flowers), which models water through a function with seven terms

which have specific values for each species, independent of the data system used to

obtain them (OLI Systems Inc, 2011).

3.1.2. TIBCOTM Spotfire®

TIBCOTM Spotfire® is an analytics software powered by a built-in artificial

intelligence engine to explore data and bring insights, mainly through visual

dashboards, predictive applications and data manipulation (TIBCO Inc, 2020). It

enables the user to program with Python, R, SAS and Matlab inside the constructed

dashboards but, most importantly, connect, manipulate and visualize data.

In this study, the software was utilized to plot the activity for the pair of ions that

are part of the analyzed salt and its saturation curve. The advantage of utilizing this

software is that the data can be selected and filtered easily when applying the method

for several different wells at the same time. Comparisons in a field level with hundreds

of wells become more efficient and accurate, as the user has freedom to perform any

kind of filtering and comparison in seconds. If the dataset is big enough and the data is

reliable, the artificial intelligence it has built in might even be able to suggest

correlations and trends unseen by the human eye, and even perform forecasts based

on historical data. For the purpose of this study, only the visualizations and filtering

attributes were utilized.

3.1.3. Data Gathering, Modelling and Plotting

The data used in this study was obtained from the aqueous phase of a

carbonate field in operation. Its ionic composition was obtained from laboratorial

analysis of samples acquired on different points. Formation brine was sampled as

produced in the beginning of production. Moreover, injection water was sampled on the

treatment plant of the production unit, and produced water was sampled at an

advanced stage of operation.

A model was created in OLI ScaleChem to predict the activity of the desired

ions on the downhole conditions (pressure and temperature), based on the seawater

percentage and utilizing as inputs the ionic analysis of formation and injection water.

Table 3.1 displays the process of inputting the brine composition, which will need to be

performed twice, once for injection water and once for the formation water.

26

Table 3.1 Interface for defining brine composition in OLI Studio. Source:

Prepared by the author.

After inputting the desired brine, it is necessary to perform a charge balance to

ensure that the brine is electronically neutral i.e. exists in a stable form.

The resultant stream shall be used to run a water-mix model for different

fractions of injected water and formation water. The outputs of this are the ionic

activities of different ions and the solubility constant of different salts, as demonstrated

in Table 3.2. This data needs to be exported for a table format, such as Microsoft Office

ExcelTM to be linked with the produced water analysis of a well in which water

breakthrough has already taken place, as per Table 3.3.

Table 3.2 Output of the water-mix model in OLI ScaleChem. Source: Prepared

by the author.

27

Table 3.3 Spreadsheet containing the values exported from OLI ScaleChem.

Source: Prepared by the author.

All the data shall be placed in TIBCO Spotfire with the appropriate connections

and filters so that the user can perform analysis and observe how close to the

saturation curve of a salt every ion pair on the produced water is and, therefore, which

are the most likely salts to drop out in the system and how likely are they to do so. The

analysis shall be performed on a well-by-well basis, but the model needs to be run only

once per reservoir, as the formation and injection water conditions should not fluctuate

much in between locations inside the same reservoir.

28

4. RESULTS AND DISCUSSIONS

4.1. Case Study

The developed model was applied to a real well, “Well A”, drilled in a carbonate

reservoir produced through waterflood mechanism. The well has a cased hole

completion, perforated in two different intervals and with no selectivity. Figure 4.1

shows that after water breakthrough, the Productivity Index decreased by 2/3 of its

initial value in just over a year, leading to huge production losses. The slope of the

decrease in productivity clearly increases as the water cut increases, which can also be

seen at Figure 4.1.

Figure 4.1 Productivity Index and Water Cut vs. Time for Well A. Source:

Prepared by the author.

Although production had fallen, the pressure difference in the flowline, that

could indicate scale deposition in the line, did not increase, as seen in Figure 4.2.

Oppositely, it was reduced due to the increased water volume in the line. The pressure

spikes are due to the temporary closing of the well.

29

Figure 4.2 Flowline dP vs Time for Well A. Source: Prepared by the author.

The productivity loss happening at the same time of the water cut increase,

together with the flowlines showing no signs of impairment, led to the question of a

possible scale deposition on the near-wellbore or perforated area, blocking the flow

from the reservoir to the well. Using Chloride as a tracer ion to calculate percentage of

seawater in the produced water mixture, the well produced formation water on the

beginning of its life and swapped for injection water as time went by, which can be

seen on the green line in Figure 4.3. This indicates that a deposition due to the water

mix mechanism could be of special importance.

Figure 4.3 Water cut (left) and injection water percentage (right) through time.

Source: Prepared by the author.

30

Scale treatments are expensive and a method that is good for one type of scale

might be ineffective for a different one, depending on the chemical composition of the

deposited salt. This is where the model adds value, since it predicts the tendency for

near-wellbore precipitation of each salt considering the composition of topsides

produced water.

4.2. OLI Modelling and Required Calculations

To assess the risk of deposition for different types of salt, this approach starts

with the simulation of a water-mix model in OLI. As inputs, pressure and temperature

conditions around the perforated interval are needed, as well as the chemical

composition of formation water and water injected in the field. For “Well A”,

temperature is 60.2ºC and pressure is 519bar, and the chemical composition is shown

in Tables 4.1 and 4.2 below.

Table 4.1 Chemical composition of formation water on selected well, screenshot

from OLI ScaleChem software. Source: Prepared by the author.

31

Table 4.2 Chemical composition of injection water on selected well, screenshot

from OLI ScaleChem software. Source: Prepared by the author.

These compositions are added as “Water Analysis” streams in the software, at

the pressure and temperature they were sampled on, meaning that since they are

usually taken on surface, they will differ considerably from the values downhole.

The water streams need to be reconciled on pH to make sure the values of

NaOH and HCl (used as default base and acid for the pH adjustment) are matching the

values required to generate the input pH. The molecular exports of the reconciled water

streams are then added to a “Mixer” stream, defined at the correct pressure and

temperature (downhole) and calculated on isothermal basis in the range from 0 to 1 on

a step of 0.01. Each of the 101 streams generated will have a different composition,

activity coefficients and scaling tendencies of the various salts. The values of activity

coefficient g and concentration (in mol) for Barium, Sulphate, Strontium, Calcium,

Bicarbonate, Carbon Dioxide and Water, plus the Alkalinity and Molality Conversion

Factor of every stream need to be exported. Also, the partitioning factor p (fraction of

species truly present as a free ion, Equation 4.1) and overall conversion factor c

(Equation 4.2). They will later be used to calculate the activity of every ion on the

32

produced water. The result will be a table such as Table 4.3, with Sulphate used as

example and simplified for visualization purposes in steps of 0.1 instead of 0.01.

𝑔𝑔𝑋𝑋(𝜙𝜙) = 𝐹𝐹𝐹𝐹𝑒𝑒𝑒𝑒 𝐼𝐼𝐼𝐼𝐼𝐼 𝐶𝐶𝐼𝐼𝐼𝐼𝑐𝑐𝑒𝑒𝐼𝐼𝑛𝑛𝐹𝐹𝑛𝑛𝑛𝑛𝑛𝑛𝐼𝐼𝐼𝐼𝑇𝑇𝐼𝐼𝑛𝑛𝑛𝑛𝑇𝑇 𝐼𝐼𝐼𝐼𝐼𝐼 𝐶𝐶𝐼𝐼𝐼𝐼𝑐𝑐𝑒𝑒𝐼𝐼𝑛𝑛𝐹𝐹𝑛𝑛𝑛𝑛𝑛𝑛𝐼𝐼𝐼𝐼

(4.1)

𝑐𝑐𝑌𝑌(𝜙𝜙) = 𝑔𝑔𝑋𝑋(𝜙𝜙) ∙ 𝑝𝑝𝑌𝑌(𝜙𝜙) (4.2)

SO4

Alkalinity Molality

Conversion Factor (w(𝜙𝜙))

Injection / Formation

Water Mixing Ratio

pBa gBa cBa

[%vol] [-] [-] [-] [mol] [kg brine / kg H2O]

0 0.96 2.50E-02 2.40E-02 2,06E-02 1,23E+00

0,1 0.95 2.73E-02 2.61E-02 1,86E-02 1,21E+00

0,2 0.95 3.01E-02 2.85E-02 1,67E-02 1,19E+00

0,3 0.94 3.34E-02 3.13E-02 1,48E-02 1,17E+00

0,4 0.92 3.75E-02 3.46E-02 1,29E-02 1,15E+00

0,5 0.91 4.26E-02 3.87E-02 1,09E-02 1,13E+00

0,6 0.89 4.92E-02 4.39E-02 9,01E-03 1,11E+00

0,7 0.87 5.81E-02 5.06E-02 7,09E-03 1,09E+00

0,8 0.85 7.08E-02 6.02E-02 5,16E-03 1,07E+00

0,9 0.84 9.05E-02 7.62E-02 3,24E-03 1,05E+00

1 0.89 1.27E-01 1.13E-01 1,31E-03 1,03E+00

Table 4.3 Table of Sulphate values of partitioning factor, activity coefficient,

alkalinity, molality conversion factor and overall conversion factor for every calculated

formation water/injection water fraction. Source: Prepared by the author.

After this, the produced water can be expressed in terms of ionic activity. As

density is an important property in the calculations, it must be estimated if not

measured. That can be done through an interpolation from the density values of the

33

formation water and injection water using Chloride as a reference, as per Equations 4.3

and 4.4.

𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝑐𝑐𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 𝑊𝑊𝑊𝑊𝐼𝐼𝐼𝐼𝑊𝑊 𝐹𝐹𝑊𝑊𝑊𝑊𝑐𝑐𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 (𝐼𝐼𝑊𝑊%) = 1 − 𝑀𝑀𝑒𝑒𝑛𝑛𝑀𝑀𝑀𝑀𝐹𝐹𝑒𝑒𝑀𝑀𝐶𝐶𝑇𝑇−𝐶𝐶𝑇𝑇𝐼𝐼𝐼𝐼𝐶𝐶𝑇𝑇𝐹𝐹𝐼𝐼− 𝐶𝐶𝑇𝑇𝐼𝐼𝐼𝐼

(4.3)

𝜌𝜌 = 𝐼𝐼𝐼𝐼𝐼𝐼𝑒𝑒𝑐𝑐𝑛𝑛𝑛𝑛𝐼𝐼𝐼𝐼𝐼𝐼𝑛𝑛𝑛𝑛𝑒𝑒𝐹𝐹𝐹𝐹𝐹𝐹𝑛𝑛𝑐𝑐𝑛𝑛𝑛𝑛𝐼𝐼𝐼𝐼∗𝜌𝜌𝐼𝐼𝐼𝐼 𝐹𝐹𝐼𝐼𝐹𝐹𝐹𝐹𝑛𝑛𝑛𝑛𝑛𝑛𝐼𝐼𝐼𝐼𝐼𝐼𝑛𝑛𝑛𝑛𝑒𝑒𝐹𝐹𝐹𝐹𝐹𝐹𝑛𝑛𝑐𝑐𝑛𝑛𝑛𝑛𝐼𝐼𝐼𝐼∗𝜌𝜌𝐹𝐹𝐼𝐼

(4.4)

Using the density, the concentration of any measured species Y per kg solvent

(mY) can be calculated through Equation 4.5.

𝑚𝑚𝑌𝑌 = [𝑌𝑌] ∙ 𝑤𝑤(𝜙𝜙)/𝜌𝜌 (4.5)

With that, the ionic activity can be calculated through Equation 4.6.

𝑚𝑚𝑔𝑔_𝑛𝑛𝑋𝑋 = 𝑚𝑚𝑌𝑌 ∙ 𝑔𝑔𝑋𝑋(𝜙𝜙) ∙ 𝑝𝑝𝑌𝑌(𝜙𝜙) = 𝑚𝑚𝑌𝑌 ∙ 𝑐𝑐𝑌𝑌(𝜙𝜙) (4.6)

To build the saturation curves and the actual plots over which the analysis will

be done, it is required to import the solubility constants from the OLI model and to

transform them to a [mg/kg H2O]² unit, multiplying the values obtained in OLI ([mol/kg

H2O]²) by 1,000,000 and the molecular weight (g/mol). These are constructed for a

chart with the 𝑚𝑚𝑔𝑔_𝑊𝑊𝑋𝑋𝑐𝑐+ value of the cation on the horizontal axis and the 𝑚𝑚𝑔𝑔_𝑊𝑊𝑋𝑋𝑛𝑛−

value for the anion on the vertical axis, being the curve a hyperbole obeying Equation

4.7.

𝑚𝑚𝑔𝑔_𝑊𝑊𝑋𝑋𝑐𝑐+ ∙ 𝑚𝑚𝑔𝑔𝑛𝑛𝑋𝑋𝑛𝑛− = 𝑚𝑚𝑔𝑔_𝐾𝐾𝑋𝑋𝑐𝑐𝑋𝑋𝑛𝑛 (4.7)

For Gypsum and Calcite, this is slightly different. The saturation curve for

Gypsum is calculated for unit activity of water, considering 𝑊𝑊𝐻𝐻2𝑂𝑂 = 1 and therefore the

plot is done into modified coordinates to account for the activity of water ([𝐶𝐶𝑊𝑊], [𝑆𝑆𝑆𝑆4]) →

�𝑚𝑚𝑔𝑔_𝑊𝑊𝐶𝐶𝑛𝑛,2+ ∙ 𝑊𝑊𝐻𝐻2𝑂𝑂 , 𝑚𝑚𝑔𝑔_𝑊𝑊𝑆𝑆𝑂𝑂4,2− ∙ 𝑊𝑊𝐻𝐻2𝑂𝑂�.

34

For Calcite, the saturation curve depends on the fugacity of CO2 and therefore

is calculated for the specified fugacity and unit activity of water, as stated in Equation

4.8, and plotted in modified coordinates considering ([𝐶𝐶𝑊𝑊], [𝐴𝐴𝐴𝐴𝐴𝐴𝑊𝑊𝐴𝐴𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐴𝐴]) → �𝑚𝑚𝑔𝑔_𝑊𝑊𝐶𝐶𝑛𝑛,2+/

𝑊𝑊𝐻𝐻2𝑂𝑂 , 𝑚𝑚𝑔𝑔_𝑊𝑊𝐻𝐻𝐶𝐶𝑂𝑂3,1−�.

𝑚𝑚𝑔𝑔𝑛𝑛𝐶𝐶𝑛𝑛,2+ ∙ 𝑚𝑚𝑔𝑔𝑛𝑛𝐻𝐻𝐶𝐶𝑂𝑂3,1−2 = 𝐾𝐾𝑒𝑒𝑓𝑓𝑓𝑓 = 𝑚𝑚𝑔𝑔_𝐾𝐾𝐶𝐶𝑛𝑛𝐶𝐶𝑂𝑂3 ∙

ℎ𝐶𝐶𝑂𝑂2 ∙ 𝑓𝑓𝐶𝐶𝑂𝑂2 ∙ 𝑀𝑀𝑊𝑊𝐶𝐶𝑂𝑂2 ∙ 1000 = 𝑚𝑚𝑔𝑔_𝐾𝐾𝐶𝐶𝑛𝑛𝐶𝐶𝑂𝑂3 ∙ 𝑚𝑚𝑔𝑔_𝑊𝑊𝐶𝐶𝑂𝑂2

(4.8)

After all these variables are calculated, every required value for the

charts are available and the analysis can be done.

4.3. Spotfire Plots and Analyses

By plotting the activity values for each cation/anion pair and its related

saturation curve, the assessment of risk of any salt deposition on a chosen part of the

system can be done. As the produced water sample that was chemically analyzed was

taken on the topsides of the producing unit, the ions dissolved on the water should not

reach the saturation curve and if they do that is likely due to the effect of additional

chemical components added to the system (i.e. scale inhibitors) or uncertainties that

this method carries related to the heterogeneities of the different drilled locations in the

reservoir and the modelling itself. Therefore, this analysis provides information about

which salt is more likely to deposit, rather than a quantitative output. This is a very

valuable information, since it can help infer the type of salt depositing on the near

wellbore area and, therefore, what is the most appropriate treatment method for

impairment reduction/production improvement, also pinpointing which wells need an

individual model and analysis with other methods. The following chapters will exemplify

the plots for the main salts deposited on oil and gas operations, stated in Chapter 2,

except for the ones involving Iron, since they are mainly deposited in the production

system and not in the near wellbore area nor inside the well, on “Well A”, the impairing

well presented in Chapter 4.1.

4.3.1. Calcium Sulphate – Anhydrite and Gypsum

For calcium sulphate, by following the procedures stated in the past chapters,

the output will be Figure 4.4 and 4.5. For Gypsum, X axis is Ca activity and Y axis is

SO4 activity, considering the activity of water aH2O (Figure 4.4) and for Anhydrite the

axes are the same but not taking into consideration the water activity (Figure 4.5). The

35

arrows are representing chronology of the sampling and can indicate a change in the

produced water chemistry from reservoir, connate water, to injection water (i.e. less

calcium, more sulphate).

Figure 4.4 Activity plot for Calcite. Source: Prepared by the author.

36

Figure 4.5 Activity plot for Anhydrite. Source: Prepared by the author.

The charts indicate that, due to the distance between the water samples and

the saturation curve for these salts, it is not expected to find Calcium Sulphate

depositions downhole of the well.

4.3.2. Barium Sulphate and Strontium Sulphate

Figure 4.6 displays the chart for Barium Sulphate, with Ba on the X axis and

SO4 on the Y axis. For this salt, the points are mostly inside the curve and there is a

strong indication of this salt’s deposition. Usually, Strontium Sulphate occurs co-

precipitated with Barium Sulphate, and when analyzing the chart in Figure 4.7, the

samples are also close to the saturation curve, corroborating for the case of this salt’s

coprecipitation.

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Figure 4.6 Activity plot for Barium Sulphate. Source: Prepared by the author.

Figure 4.7 Activity plot for Strontium Sulphate. Source: Prepared by the author.

As these salts have a natural occurring radioactivity, gamma ray logging can be

done to ensure the existence of the salt prior to the treatment and scale squeeze

planning. Since there is indication of scale deposition for these specific salts, i.e.

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productivity drop and points near saturation curve, they need to be further investigated.

Possible approaches could be suspended solids analysis and logging. Sulphate-based

scale builds up slowly but is very hard to dismantle, possibly creating unrepairable

damage.

4.3.3. Calcium Carbonate

For Calcium Carbonate, Figure 4.8, most of the chemical analysis are also near

the threshold or above it, indicating that there might be Calcium Carbonate deposition.

Analyzing the suspended solids on the produced water could ensure that the well is

being treated for the right type of salt and in the right manner.

Figure 4.8 Activity plot for Calcium Carbonate. Source: Prepared by the author.

4.4. Treatment, Prevention and Results

A caliper tool was run through the aforementioned well and reported changes in

diameter, particularly below the perforations. This is an indication of scale deposition in

the area, as predicted by the model. Gamma ray also found several radiation points

throughout the wellbore. The well was treated with diesel, solvent, EDTA and HCl,

aiming for the dissolution of sulphate-based scales and calcium carbonate, as

predicted above, plus scale inhibitor to postpone the next deposition. Figure 4.9 shows

that productivity doubled after the treatment, marked as a black line in Figure 4.9,

which would confirm its efficiency, but several of the gamma ray reaction spots did not

disappear and the productivity quickly starts dropping again, creating the possibility that

39

the chosen chemical compound for scale inhibition did not adhere to the rock as

expected, or volumes were not enough.

Figure 4.9 Productivity Index before and after the scale treatment. Source:

Prepared by the author.

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5. CONCLUSIONS

As energy demand increases and the world develops, while petroleum is still

the main energy source worldwide, production protection will need to play a bigger role

in the energy supply. Scaling is still one of the biggest causes of production loss, and

methods to detect the problem before it develops are required. This study introduces a

new methodology to perform surveillance on production wells, avoiding unnecessary

losses and maintaining safe operations.

This study successfully presented a literature review of the issue of inorganic

scaling in oilfield operations, containing its definition, formation mechanisms, usual

salts deposited on oilfield operations, operational problems, associated risks and

preventive and corrective measures. It also introduced he crucial chemistry definitions

to understand the process and the generated model, such as ionic activity, solubility

and saturation ratio. It shall be utilized from here onwards as an important reference for

future works and as introductory material for learning about the issue.

The developed model allows the analysis of hundreds of wells in a second, as

the only requirement is the selection of the desired wells on the Spotfire panel and the

pre-loaded charts will come up. It also permits the comparison between different wells

in the same field, qualitatively knowing which ones are more critical and simplifying a

lot the required analysis to prioritize treatments and, therefore, the decision-making

process. By providing information about which salt is more likely to deposit, it unlocks

the possibility of not only choosing the correct well to prioritize but to assess the correct

treatment method for impairment prevention and remediation.

On the case study, the results brought by the developed model, indicating

barium sulphate and calcium carbonate deposition, were confirmed by physical and

mechanical methods for the presented well. Therefore, the model has proved its

accuracy for qualitative analysis. The cost associated with running it is non-existent

compared to the ones of industry-utilized tools, requiring only man-power and a

software license instead of hundreds of thousand dollars in inspection tools. It does

not, however, replace a more detailed case-by-case analysis on the wells that are

shown to be problematic by the model itself, working as a diagnostic tool and not

necessarily as a treatment-design tool.

Important future work could be done to improve this tool. First, utilizing the

Artificial Intelligence contained in TIBCO Spotfire to generate forecasts of produced

water chemistry and scale deposition based on historical data. Moreover, generating

new data sets for wells surrounding the analyzed produced but that have not had water

breakthrough yet. Finally, additional detailed work on the quantitative side of the model,

41

possibly lowering the space taken for a region of the reservoir instead of the entire

reservoir, to allow for a more quantitative analysis that might actually output a

probability of deposition, as the historical data can be manipulated and analyzed in

Spotfire through statistical methods.

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