UNIVERSIDADE ESTADUAL DE CAMPINAS
Faculdade de Engenharia Mecânica e Instituto de Geociências
ANTÔNIO CAMILO RIBEIRO SANTOS SOUZA BARTOLY DUARTE
PVT Properties Study of Mixture of Methane
and Glycerin Based Drilling Fluids
Estudo das Propriedades PVT de Misturas de
Metano e Fluidos de Perfuração à Base
Glicerina
CAMPINAS
2020
ANTONIO CAMILO RIBEIRO SANTOS SOUZA BARTOLY DUARTE
PVT Properties Study of Mixture of Methane
and Glycerin Based Drilling Fluids
Estudo das Propriedades PVT de Misturas de
Metano e Fluidos de Perfuração à Base
Glicerina
Dissertation presented to the Mechanical Engineering Faculty and Geosciences Institute of the University of Campinas in partial fulfillment of the requirements for the degree of Master in Petroleum Sciences and Engineering in the area of Exploitation.
Dissertação apresentada à Faculdade de Engenharia Mecânica e Instituto de Geociências da Universidade Estadual de Campinas como parte dos requisitos exigidos para a obtenção do título de Mestre em Ciências e Engenharia de Petróleo na área de Explotação.
Orientador: Prof. Dr. Paulo Roberto Ribeiro
Coorientadora: Profa. Dra. Nara Angélica Policarpo
ESTE EXEMPLAR CORRESPONDE À VERSÃO FINAL DA DISSERTAÇÃO DEFENDIDA PELO ALUNO ANTÔNIO CAMILO RIBEIRO SANTOS SOUZA BARTOLY DUARTEE ORIENTADA PELO PROF. DR. PAULO ROBERTO RIBEIRO.
____________________________ Assinatura do Orientador
CAMPINAS
2020
Ficha catalográfica
Universidade Estadual de Campinas Biblioteca da Área de Engenharia e Arquitetura
Luciana Pietrosanto Milla - CRB 8/8129
Duarte, Antônio Camilo Ribeiro Santos Souza Bartoly, 1982- D85p DuaPVT properties study of mixture of methane and glycerin based drilling
fluids / Antônio Camilo Ribeiro Santos Souza Bartoly Duarte. – Campinas, SP : [s.n.], 2020.
DuaOrientador: Paulo Roberto Ribeiro. DuaCoorientador: Nara Angélica Policarpo.
DuaDissertação (mestrado) – Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica.
Dua1. Poços de petróleo - Fluídos de perfuração. 2. Glicerina. 3. Engenharia do petróleo. 4. Poços de petróleo - Perfuração. I. Ribeiro, Paulo Roberto, 1961-. II1961-. Policarpo, Nara Angélica, 1981-1961-. III1961-. Universidade Estadual de Campinas1961-. Faculdade de Engenharia Mecânica. IV. Título.
Informações para Biblioteca Digital
Título em outro idioma: Estudo das propriedades PVT de misturas de metano e fluidos de perfuração à base glicerina Palavras-chave em inglês:
Oil wells - Drilling fluids Glycerin
Petroleum engineering Oil wells - Drilling
Área de concentração: Explotação
Titulação: Mestre em Ciências e Engenharia de Petróleo Banca examinadora:
Paulo Roberto Ribeiro [Orientador] Pedro de Alcântara Pêssoa Filho Sérgio Nascimento Bordalo Data de defesa: 27-02-2020
Programa de Pós-Graduação: Ciências e Engenharia de Petróleo Identificação e informações acadêmicas do(a) aluno(a)
- ORCID do autor: 0000-0002-2743-5405
UNIVERSIDADE ESTADUAL DE CAMPINAS
FACULDADE DE ENGENHARIA MECÂNICA E INSTITUTO DE
GEOCIÊNCIAS
DISSERTAÇÃO DE MESTRADO ACADÊMICO
PVT Properties Study of Mixture of Methane
and Glycerin Based Drilling Fluids
Estudo das Propriedades PVT de Misturas de
Metano e Fluidos de Perfuração Base
Glicerina
Autor: Antônio Camilo Ribeiro Santos Souza Bartoly Duarte Orientador: Prof. Dr. Paulo Roberto Ribeiro
Coorientadora: Profa. Dra. Nara Angélica Policarpo
A Banca Examinadora composta pelos membros abaixo aprovou esta Dissertação/Tese: Prof. Dr. Paulo Roberto Ribeiro, President
DE/FEM/University of Campinas
Prof. Dr. Pedro de Alcântara Pêssoa Filho PQI/EP/University of São Paulo
Prof. Dr. Sérgio Nascimento Bordalo DE/FEM/ University of Campinas
A Ata de Defesa com as respectivas assinaturas dos membros encontra-se no SIGA/Sistema de Fluxo de Dissertação/Tese e na Secretaria do Programa da Unidade.
Dedicatória
Uma certa vez o Ministro de Estado Délio Jardim de Matos, em viagem oficial a um pequeno vilarejo do interior da Bahia, conversava com dois habitantes da cidade de Tanhaçu. Eram amigos e um deles, um dos homens mais ricos da região, fez questão de apresentar o outro para o Ministro: "Tá vendo esse homem aqui? Pois bem, eu sou um "industrial" e nem assim consegui formar um filho "doutor". Já ele conseguiu formar três filhos "doutor" vendendo água choca." Essa é a história do meu avô Camilo, ou como ficou conhecido – Seu Camilo, um homem à frente do seu tempo. Nasceu e viveu toda a sua vida em um pequeno interior da Bahia, à época com menos de 20 mil habitantes, e que, portanto, podemos imaginar as barreiras que se ainda hoje são impostas à maioria dos habitantes das pequenas cidades do Brasil, imagine há 50 anos. Tanto ele como minha avó, semianalfabetos, acreditavam piamente em um caminho para a liberdade e independência plena de seus filhos: a educação.
Acknowledgment
I would like to express my sincere and profound obligation towards all personages who have helped me in this endeavor. Without their active guidance, help, cooperation, and encouragement, I would not have gone through that stage of my life.
I acknowledge with a deep sense of reverence, my gratitude towards my parents and members of my family, who always supported me morally as well as economically.
I also acknowledge with a deep sense of endearment, my gratitude towards my friends who directly and indirectly helped me to complete this research.
I am inexpressibly indebted to my advisor Prof. Dr. Paulo Roberto Ribeiro for honorable guidance and encouragement to accomplish this assignment.
I am extremely grateful and pay my gratitude to my co-advisor Prof. Dr. Nara Angelica Policarpo for her valuable guidance and support for the completion of this research.
I feel indebted to the following persons from Prof. Ribeiro´s research group: Dr. Nilo Ricardo Kim, researcher;
Leandro Augusto Fernandes, PVT technician;
Felipe Chagas, computational analysis doctoral candidate; Vinicius Boschini, scientific initiation undergraduate student.
I extend my gratitude to the Petroleum Engineering Division, Energy Department, Mechanical Engineering School, as well as the Center for Petroleum Studies, both at State University of Campinas - UNICAMP, for furnishing the laboratory facilities.
Finally, my gratitude goes to Petróleo Brasileiro S.A. (Petrobras), specially to the Drilling Fluids Division of the Research Center Leopoldo Américo Miguez de Mello (CENPES), for providing my scholarship and the fluid samples"
To penetrate and dissipate these clouds of darkness, the general mind must be strengthened by education. Thomas Jefferson
Resumo
À medida que a indústria de petróleo e gás avança para locais ainda mais remotos, especialmente em áreas offshore, as profundidades podem chegar a 3400 m de lâmina d’agua e até 7000 m de profundidade vertical. Esses são os desafios que a indústria de petróleo e gás está superando para acompanhar o crescimento constante na demanda por energia em todo o mundo. Durante uma operação de perfuração de poço, um dos principais riscos é o evento de um kick que pode levar a uma situação de blowout quando não for detectado e circulado adequadamente. No caminho da evolução dos fluidos de perfuração, a lama de base sintética (SBM) é comumente usada em plataformas offshore devido a seus benefícios ao alto nível de complexidade, especialmente em cenários de águas profundas e ultraprofundas. No entanto, quando o gás de formação se dissolve na lama devido à alta pressão e alta temperatura, a complexidade da detecção de kick aumenta significativamente. Mais ainda, as preocupações ambientais levaram a maioria das agências governamentais ao redor o mundo a elaborar regulamentos muito rigorosos que devem ser seguidos. Nesse contexto, a glicerina surge como um potencial candidato a desempenhar um papel fundamental como lama base para perfuração (GBM). Este trabalho tem o objetivo principal de analisar o comportamento de PVT de misturas de metano com glicerina e soluções de glicerina/salmoura como base para fluidos de perfuração, através da determinação experimental, densidade e fator de volume de formação através de uma célula PVT visual de alta resolução, sob condições de teste ATAP. Testes experimentais foram realizados até 80°C e pressões de até 55 MPa, revelando a baixa solubilidade do gás na solução. Devido à pouca informação disponível na literatura, a maioria dos dados coletados é nova. As correlações matemáticas são conduzidas para ajudar a fornecer respostas científicas aos problemas de controle de poço enfrentados durante os procedimentos operacionais.
Abstract
As the oil and gas industry advances to even more remote areas, especially in offshore areas, depths are increasing as 3400 m water-depth or up to 7000 m TVD. These are the challenges that the oil and gas industry is overcoming to keep up with the constantly growing demand for energy worldwide. Those accomplishments are results of heavy investment in multidisciplinary research and technologies targeting not only the new exploration frontier but also making the existing production basins more efficient and safer. During a well drilling operation, one of the major risks is the event of a kick which can lead to a blowout situation when it is not properly detected and circulated. Drilling fluids are the primary barrier against a kick. In the path of drilling fluids evolution, synthetic-based mud (SBM) is commonly used on offshore rigs due to its benefits to the high level of complexity, especially at deep and ultra-deep-water scenarios. However, when formation gas dissolves in the mud due to high pressure and high temperature (HPHT) the complexity of kick detection spikes. Even more, environmental concerns raised a red flag on SBM usage and evaluating the potential impact on the marine environment most government agencies around the world made very strict regulations that must be followed. Considering both aspects, safety and environment concern, glycerin emerges as a potential candidate to perform a key role as base mud (GBM). At first, GBM has the potential to behave as SBM due to its benefits, such as lubricity and shale stabilization, for example, and, at the same time, GBM has the same characteristics as WBM with very low or no methane solubility, the major component of natural gas. Additionally, GBM is also considered more environmentally friendly than SBM. This present study has the main objective to analyze the PVT properties of methane and glycerin-based drilling emulsions by experimental determination of bubble point, solubility, density and formation volume factor of the saturated and sub-saturated fluid mixture through a visual high-resolution PVT cell under HPHT testing conditions. Experimental tests were run at up to 80°C and pressures up to 55 MPa. Due to so limited information available in the literature, most of the data collected are new. Mathematical correlations are conducted so it can help provide scientific answers to the well control problems faced during operations procedures.
List of Figures
Figure 1. 1 – Brief chronology of modern drilling fluid (adapted from Cheung et. al, 2001) . 20
Figure 2. 1 – Glycerol (adapted from shutterstock website). ... 24
Figure 2. 2 – Global biodiesel production and crude glycerol price from 2003 to 2020 (OECD-FAO, 2015). ... 25
Figure 2. 3 – Transesterification Process for Biodiesel (adapted from Rivaldi et at., 2008). .. 26
Figure 2. 4 - (A) Crude glycerin (B) Pure glycerin (Marbun et al., 2013). ... 26
Figure 2. 5 – Brief chronology of drilling fluid studies. ... 27
Figure 2. 7 – Phase equilibria in the methane-diesel system at 37.7C (Thomas et al., 1982). 32 Figure 2. 6 - Brief chronology of PVT drilling fluid studies ... 33
Figure 2. 8 – Phase envelope of methane with 4 oil bases, measured and calculated at 90C (Berthezene et al., 1999). ... 34
Figure 3. 1 – Experimental apparatus. ... 37
Figure 3. 2 – Experimental system schematic. ... 37
Figure 3. 3 – PVT Cell ... 38
Figure 3. 4 – High pressure positive displacement pump. ... 40
Figure 3. 5 – High-resolution color CCD camera. ... 41
Figure 3. 6 – High-resolution color monitor and vertical shift controller. ... 41
Figure 3. 7 – Rotational Rheometer Haake Mars III. ... 42
Figure 3. 8 – Anton Paar DMATM 4200 M. ... 43
Figure 3. 9 - Shaker incubator and ultrasound used in emulsion homogenization. ... 43
Figure 3. 10 – PVT system schematic... 45
Figure 3. 11 – Schematic of cell visualization (Atolini, 2008). ... 48
Figure 4. 1 – Density versus temperature at 1.01 MPa. ... 51
Figure 4. 2 – Crude glycerin density as a function of pressure measured in PVT cell. ... 52
Figure 4. 3 – 50/50 glycerin/brine density as a function of pressure measured in PVT cell. .. 52
Figure 4. 4 – Crude glycerin density as a function of temperature measured in PVT cell. ... 53
Figure 4. 5 - 50/50 glycerin/brine density as a function of temperature measured in PVT cell. ... 54
Figure 4. 6 – Crude glycerin compressibility as a function of pressure and temperature. ... 55
Figure 4. 7 – 50/50 glycerin/brine compressibility as a function of pressure and temperature. ... 56
Figure 4. 8 – Isobaric expansion of crude glycerin as a function of temperature and pressure 57 Figure 4. 9 – Isobaric expansion of 50/50 glycerin/brine as a function of temperature and pressure ... 57
Figure 4. 10 – Viscosity versus shear rate and temperature for water and GBM ... 58
Figure 4. 11 – Flow curves as a function of temperature for water and GBM. ... 60
Figure 4. 12 – Viscosity as a function of shear rate and distilled water temperature. ... 61
Figure 4. 13 – Olefin viscosity as a function of shear rate and temperature. ... 61
Figure 4. 14 – Apparent viscosity of 65/35 olefin/brine emulsion as a function of shear rate and temperature. ... 62
Figure 4. 15 – Small bubbles or impurities. ... 64
Figure 4. 16 – Deaeration process. ... 65
Figure 4. 17 – Methane and crude glycerin at 8000 psi (on the left, 10% of CH4, and the right, 20% of CH4). ... 66
Figure 4. 18 – Pressure as a function of the net volume of methane/glycerin mixture to 10% methane in the mixture (Vstd = 19,876 .10-6 m3). ... 67
Figure 4. 19 – Pressure as a function of the net volume of methane / 50/50 glycerin mixture to 10% methane in the mixture (Vstd = 18,274 .10-6 m3). ... 67
Figure 4. 20 – Pressure versus net volume of methane/glycerin mixture for methane fractions from 10 to 40%, at 20°C. ... 68
Figure 4. 21 – Density of methane/crude glycerin mixture as a function of pressure and temperature for methane fractions from 10% to 50% in the mixture in biphasic condition. ... 70
Figure 4. 22 – Density of methane/(50/50) glycerin/brine mixture as a function of pressure and temperature for methane fractions of 10% and 20% in the mixture in biphasic condition. ... 70
Figure 4. 23 - Crude glycerin and (50/50) glycerin/brine versus pressure, at 20C. ... 71
Figure 4. 24 – Oil formation volume factor for methane/glycerin mixture in biphasic condition for all gas molar fractions in the mixture. ... 72
Figure 4. 25 – Oil formation volume factor for methane/(50/50)glycerin mixture in biphasic condition for all gas molar fractions in the mixture. ... 72
Figure 5. 1 – Oil formation volume factor versus pressure (Ahmed, 2010). ... 74
Figure 5. 2 – Oil formation volume factor versus pressure (adapted from Ahmed, 2010). ... 74
Figure 5. 3 – Glycerin formation volume factor of methane/glycerin mixture experimental values calculated via adjusted Bo correlation. ... 77
Figure 5. 4 - Glycerin formation volume factor adapted from Bo calculation by Vasquez and Beggs, 1980. ... 77
Figure 5. 5 – Glycerin formation volume factor of methane/glycerin mixture experimental values calculated via adjusted Bw correlation... 79
Figure 5. 6 - Glycerin formation volume factor adapted from Bw calculation by Ahmed (2010). ... 79
Figure 5. 7 - Glycerin formation volume factor of methane/glycerin mixture experimental values calculated the best LabFit correlation. ... 80
Figure 5. 8 - Glycerin formation volume factor calculated from the best LabFit correlation. . 81
Figure 5. 9 – Glycerin density of methane/glycerin mixture experimental values calculated via adjusted Bo correlation. ... 82
Figure 5. 10 - Glycerin density adapted from Bo calculation by Vasquez and Beggs, 1980... 83
Figure 5. 11 – Glycerin density of methane/glycerin mixture experimental values calculated via adjusted ρw correlation... 84
Figure 5. 12 - Glycerin density factor adapted from ρw calculation by Ahmed (2010). ... 84
Figure 5. 13 - Glycerin density of methane/glycerin mixture experimental values calculated the best LabFit correlation. ... 85
Figure 5. 14 - Glycerin density calculated from the best LabFit correlation. ... 86
Figure 5. 15 – Snapshot of the Unikick interface. ... 87
Figure 5. 16 – Choke line pressure curve for GBM. ... 89
List of Tables
Table 2. 1 – Physical and chemical properties of glycerol (adapted from Quispe, 2013). ... 30
Table 2. 2 - Average viscosity and heat of combustion of crude glycerol from different feedstock (adapted from Quispe, 2013). ... 31
Table 4. 1 - Densities at atmospheric pressure drilling fluids. ... 50
Table 4. 2 - Linear adjustments for density as a function of temperature per fluid type. ... 51
Table 4. 3 – Correlations adjusted for pure glycerin densities measured in the PVT cell at temperatures between 20 and 80 C and pressures up to 55 MPa. ... 52
Table 4. 4 - Correlations adjusted for 50/50 glycerin/brine densities measured in the PVT cell at temperatures between 20 and 80°C and pressures up to 55 MPa. ... 53
Table 4. 5 – Correlations adjusted for crude glycerin densities measured in the PVT cell at temperatures between 20 and 80oC and pressures up to 8000 psi. ... 54
Table 4. 6 – Correlations adjusted for 50/50 glycerin/brine densities measured in the PVT cell at temperatures between 20 and 80oC and pressures up to 8000 psi. ... 54
Table 4. 7 – Crude glycerin isothermal compressibility ... 56
Table 4. 8 – 50/50 glycerin/brine isothermal compressibility ... 56
Table 4. 9 – Viscosity as a function of temperature for GBM. ... 59
Table 4. 10 – Newtonian rheology models adjusted for GBM... 63
Table 4. 11 – Viscosities measured and adjusted as a function of temperature for GBM. ... 63
Table 5. 1 – Coefficients using Vasquez and Beggs, (1980) Bo proposed calculation. ... 76
Table 5. 2 - Coefficients using Ahmed (2010) Bw proposed calculation. ... 78
Table 5. 3 - Coefficients using the best LabFit correlation calculation. ... 80
Table 5. 4 - Coefficients using Vasquez and Beggs, (1980) ρo proposed calculation. ... 82
Table 5. 5 – Coefficients using Ahmed (2010) ρw proposed calculation. ... 83
Table 5. 6 - Coefficients using the best LabFit correlation calculation. ... 85
Table 5. 7 – Well data (Case 1). ... 88
Table 5. 8 - Well data (Case 2). ... 91
List of Abbreviations and Acronyms
API American Petroleum Institute ATAP Alta Temperatura Alta Pressão
BBDF Biodiesel-Based Invert Emulsion Drilling Fluid
BCE Before Common Era
BOP Blowout Preventer
CCE Constant Composition Expansion ECD Equivalent Circulating Density
EU Europe Union
FAME Fatty Acid Methyl Esters GBM Glycerin Based Mud
HPHT High Pressure High Temperature HHV Higher Heating Value
ID Internal Diameter
IUPAC International Union of Pure and Applied Chemistry MAD Mean Absolute Deviation
NIST National Institute of Standards and Technology
NPBMs Nano-Silica and Pure-Bore Additives Based Brine Muds NPT Non-Productive Time
OBM Oil-Based Mud
PVT Pressure-Volume-Temperature SBM Synthetic-Based Mud
SICP Shut-In Casing Pressure SIDPP Shut-In Drill Pipe Pressure USA United States of America
Nomenclature
Latin Letters
°API API density [°API]
Bg Gas formation volume factor [m3/m3std]
Bo Oil formation volume factor [m3/m3std]
Bob Oil formation volume factor at bubble point [m3/m3std]
Boi Oil formation volume factor at initial condition [m3/m3std]
Bw Water formation volume factor [m3/m3std]
c0 Isothermal compressibility of fluid [MPa-1]
Em Measured erros [%]
fcell Factor that converts unit of height to volume [cm/cm3] H Height read on the image capture system monitor [cm] HMeniscus Interface height of gas-liquid phase [cm]
m Mass [g]
P Pressure [MPa]
Pb Bubble pressure [MPa]
Pi Initial pressure [MPa]
Rs Solubility ratio [m3std/m3std]
Rsb Solubility ratio at bubble point [m3std/m3std]
R2 Correlation coefficient -
T Temperature [°C]
V Volume at specific pressure and temperature [cm3]
Vdead Volume occupied by the mixer [cm3]
Vfreegas Volume of free gas at P and T [cm3]
Vgasstd Volume of free gas at standard conditions [cm3std] Vgdissolvedstd Gas volume dissolved at standard condition [cm3std]
VL Liquid-phase volume [cm3]
VM Volume of mixture [cm3]
Vo Volume of oil at P and T [cm3]
Voilstd Volume of oil at standard conditions [cm3std]
y Gas molar fraction -
Greek Letters
Isobaric expansion of fluid [°T-1]
Shear rate [s-1]
gs Specific mass of gas [-]
Apparent viscosity [cP]
Viscosity [cP]
Density [kg/m3]
o Oil density [kg/m3]
ob Oil density at bubble point [kg/m3]
w Water density [kg/m3]
Summary
1. INTRODUCTION ...19
1.1 Objectives of The Present Work ... 21
1.2 Outline ... 21
2. LITERATURE REVIEW ...23
2.1 Propane-1,2,3-triol ... 23
2.2 Glycerin as Drilling Fluid ... 27
2.3 PVT Properties Studies of Drilling Fluids ... 31
3. EXPERIMENTAL APPARATUS AND PROCEDURE ...37
3.1 PVT Experimental Apparatus ... 37
3.1.1 PVT Cell ...38
3.1.2 Pump 39 3.1.3 Data Acquisition System ...40
3.2 Rheology Measurement ... 42
3.3 Density Measurement... 42
3.4 Experimental Procedure ... 44
3.5 Constant Composition Expansion – CCE ... 44
4. EXPERIMENTAL RESULTS ...50
4.1 Density ... 50
4.2 Rheology Tests ... 57
4.3 PVT Properties of Methane/Glycerin Mixture ... 64
4.3.1 Saturation Pressure ...65
4.3.2 Density ...68
4.3.3 Oil Formation Volume Factor ...71
5. THERMODYNAMIC MODELING FOR METHANE/GLYCERIN MIXTURE ...73
5.1 Oil Formation Volume Factor Correlations ... 73
5.1.2 Bw – Modeling Using Ahmed (2010) ...78
5.1.3 Bo – Modeling Proposed Using LabFit ...80
5.2 Density Correlations ... 81
5.2.1 ρo – Modeling Using Vasquez and Beggs (1980) ...81
5.2.2 ρw – Modeling Using Ahmed (2010) ...83
5.2.3 ρo – Modeling Proposed Using LabFit ...85
5.3 Well Control Example ... 86
5.3.1 Case 1 – Choke Manifold Pressure Curve ...86
5.3.2 Case 2 – Pit-Gain ...90 6. CONCLUSIONS...93 6.1 Literature Review... 93 6.2 Experimental Results... 93 6.3 Recommendations... 95 REFERENCES ...96
1. INTRODUCTION
In 2016, Total Company in cooperation with Exxon Mobil claimed they had broken the world record for the deepest offshore well by water depth. Located approximately 250 km from the Uruguayan coast, the well (Raya-1 prospect) was drilled in a water depth of 3400 m and 3000 m below the seabed. Unfortunately, Raya-1 wildcat came out dry (no production or proven reserves) (Maersk Drilling, 2019). A year early, Petrobras had drilled a well (3-SES-184) located 92 km from the Brazilian coast, with a total depth of 6060 m and 2990 m water depth. The 3-SES-184 confirmed the presence of light oil (Petrobras, 2015).
Those wells are examples of the challenges that the oil and gas industry are overcoming in order to keep up with the constantly growing demand for energy worldwide. Those accomplishments are results of heavy investment in multidisciplinary research and technologies targeting not only the new exploration frontier but also making the existing production basins more efficient and safer. Safety is the keystone of this revolution. To be able to drill kilometers of a deep well in a remote offshore area, for example, a robust safety plan must be followed. From rigorous regulations governed by local agencies, through internal companies’ culture, to international best practices, everything must be accounted for. During a well drilling operation, one of the major risks is the event of an undesired inflow from the formation into well (kick). When the undesired inflow is not properly detected and circulated, it may lead to a blowout situation. According to Santos (2013), a blowout is defined as an uncontrolled inflow from the formation into well and then to surface, seabed or other formation in contact with the well. The Macondo blowout or Deepwater Horizon disaster in 2010 is one of the worst offshore oil rig tragedies when eleven lives were lost and 3.19 million barrels of oil spilled in the Gulf of Mexico (Turley, 2019). The author reveals, even though the blowout did not happen during the drilling operation, it was during the preparation to a temporary abandonment, a failure to detect and solve a kick caused the loss of human lives, brutal environment impact, social-economic crash on the coastal communities, and a huge company brand damage.
Drilling fluids (mud) are the primary barrier against a kick (hydrostatic head). However, it took years before drilling fluids were presented as a means of controlling an inflow. The first data of usage comes from the remote years of 600 BCE when muddy water was used as a softening agent by Chinese (Darley and Gray, 1988). According to Eustes III (2011), only in
1913, it was used to control pressure in Oklahoma, USA and later, in 1926, the Louisiana geologist Ben K. Stroud patented it as means for controlling the flow of gas, oil, and water under pressure from the well (Figure 1.1). In the beginning, the water-based mud (WBM) was the only commercial option, but, in 1942, invert emulsion oil-based mud (OBM) became commercially available (Miller, 1942). This was a game-changer, especially after OBM was used in the Los Angeles basin in 1960 (Eustes III, 2011). Even though, the benefits of addition of oil was reported before, for example, in 1934 and 1937.
The results of OBM used in Los Angeles basin, specifically enabling to drill at high rates and serving to control reactive shale (naturally inhibitive), had a major impact in drilling fluids technology (Eustes III, 2011). From there, diesel became the dominant OBM and mineral oil was also available. As OBM gained popularity, environmental concerns also spiked. In 1986, 90% of North Sea wells were using lower toxicity OBM and, in 1988, the OBM usage was restricted worldwide especially in the offshore environment (Cheung et. al, 2001). Most of the restraint around the world, at first, was the prohibition of overboard discharge when the OBM contained diesel (Blaier, 1993). However, evaluating the potential impact on the marine environment most government agencies around the world banned the OBM use or made it so strict that companies preferred not to use it.
Synthetic-based mud (SBM) was introduced in 1990 with the objective to perform, at least, as well as OBM and it must follow those rigorous regulations. Since the first SBM (Ester) was introduced in 1990, many other SBM emerged with the potential to reach that goal (Eustes III, 2011). However, more research and development must be conducted to better understand those drilling fluids. With this scenario, Daniel Guy Pomerleau, in 2008, patented glycerol-based drilling fluid. A new drilling fluid formulation composed of a mixture of glycerin and water, which has the potential to perform as the OBM, but with the benefit of being environment friendly. Regarding to safety, the understanding of thermodynamic behavior on mixtures of gas and drilling fluid is essential for the planning of how a kick should be circulated out of the well in a controlled manner, especially for new formulations in which there is a lack of data. The theory has shown that glycerin-based drilling fluid is immiscible with methane, for example. Nevertheless, no experiments were run to confirm it or not.
Figure 1.1 – Brief chronology of modern drilling fluid (adapted from Cheung et. al, 2001). 1 84 5 /1 8 9 0s 1845 -Circulating fluid while drilling, patented in England. 1860 -Circulation of fluid to lift cuttings. 1866 -Rotary-rig design patent is issued. 1890s - Mud-making clays are used in TX, USA. 1 90 0 /1 9 2 0s 1901 -Spindletop discovery in Beaumont, TX, USA. 1913 - Mud is used to control pressure in OK, USA. 1922 -Usage of barite as weight mud. 1926 -Louisiana geologist Ben K. Stroud patented "means for controlling the flow." 1930s 1932 -Damage from mud is recognized in CA, USA. 1934 - Crude oil is added to reduce pipe stuckness in OK, USA. 1936 -Regular standards for testing are studied. 1937 -increased drilling rates by oil addition are reported. 1938 - API published regular standards. 1 94 0 /1 9 7 0s 1942 - OBM become commercially available. 1945 - First trainings on the "Principles of Drilling Mud Control." 1960 - OBM is used in Los Angeles basin, CA, USA. 1970 - OBM are used increasingly as means to control reactive shales. 1980s 1980 - Diesel become the dominant OBM. 1983 -Mineral Oil is introduced. 1986 - 90% of North Sea wells use lower toxicity OBM. 1988 -Environment al concerns led to worldwide restrictions in use of OBM. 1990s 1990 - The first SBM (Ester). 1990 - Drilling operations began moving into deeper water 1991 -Polyalphaolefin is introduced. 1994 - Linear alphaolefin-based muds are developed. 1996 - Internal Olefin synthetic-base mud introduced. 2000s 2002 - SBM formulated with an eater or olefin blend became widely used, especially in deepwater operations 2008 - Daniel Guy Pomerleau, Calgary - CA patented in US Glycerol Based Drilling Fluid. until now -Research on SBM to improve nontoxic system continue.
The information on how much gas will be dissolved in the fluid at a given pressure and at which pressure the first bubble appears (bubble point), if existent, is critical to any well control. A Pressure-Volume-Temperature (PVT) study from properties determined by experiments such as saturation point, solubility, specific mass, density, compressibility, and formation volume factor will help not only to develop a proper well control plan but also to feed well control simulator systems.
1.1 Objectives of The Present Work
From the mentioned perspective, the main objective of the present work is to measure and evaluate the pressure, volume, and temperature properties of methane and glycerin-based drilling fluid mixtures, under high-pressure and high-temperature conditions, and:
• To study these parameters at pressures from 0 to 55 MPa, temperatures of 20 to 80°C, and molar fraction of methane of 10 to 50% on a mixture of:
1. Methane (CH4) and glycerin-based fluid;
2. Methane (CH4) and 50/50 glycerin/water solution based fluid;
• To simulate the well condition behavior considering the influx of gas (gas enrichment) and the interaction of these mixtures;
• To obtain the correlation from experimental data to perform mathematical modeling of oil formation volume factor and density to feed simulator system.
1.2 Outline
The dissertation was divided in six chapters that follows:
• Chapter 1: It shows a brief introduction of this dissertation, its importance, and it gives an overview of the main points that will be discussed;
• Chapter 2: It contains the literature review presenting previously conducted studies on drilling fluids. It gives an overview of the main characteristics of the glycerin-based fluid and the contributions of PVT studies to well control;
• Chapter 3: It describes the experimental apparatus, focusing on the PVT cell, the pump, and the data acquisition system with their respective operation limits, and the experimental procedure showing how the PVT equipment was operated and density and rheology measurements were taken;
• Chapter 4: It presents and discusses the experimental results obtained for the fluids of interest as a function of pressure, temperature, and composition. The thermodynamic properties determined are viscosity, isobaric thermal expansion, compressibility, saturation pressure, density, and oil formation volume factor;
• Chapter 5: It shows mathematical correlations from the collected experimental data obtained with the aid of a computer program and simulate two examples of well control comparing GBM and SBM;
• Chapter 6: It provides the main conclusions of this present study and recommendations for future projects.
2. LITERATURE REVIEW
The first drilling fluid commercially used in the petroleum industry was water-based, thus, its usage became common everywhere around the world. In general, WBM is used in low pressure and low-temperature fields while oil-based fluids and synthetic-based fluids are typically used in HPHT fields, in water-sensitive formation, and complex configuration. WBM is environment-friendly, non-toxic and less expensive. On the other hand, OBM and SBM are toxic, more expensive, and their biodegradation is slow. Currently, there are few drilling fluids formulations considered environmentally friendly and at the same time commercially available (Malgaresi et al., 2018). Still, OBM and SBM provide better performance regard to the rate of penetration, lubricity, resistance to contaminants, and retarded clay swelling (Eustes III, 2011).
Environmental regulations and toxicity tests, as mention before, are becoming more restrictive. Especially on OBM and SBM, for example, it goes from zero discards of fluid and cuttings without treatment to the banishment of the use of OBM (OSPAR, 2003/04). The race to find an alternative solution has brought many drilling fluids formulations to be tested, not only to meet environmental regulations but also to prevent, mitigate or remove formation damage. However, most of them face either technical problems or the lack of study on the interactions between the drilling fluid and the potential formation, such as the drilling fluid formulation proposed by Yang et al. (2017), Nano-Silica and Pure-bore additives based brine mud (NPBMs). Economic viability is also an issue, since some drilling fluids, such as the biodiesel-based invert emulsion drilling fluid (BBDF) proposed by Li et al. (2015), need to be processed in a very complex technological process. Nevertheless, preliminary studies on glycerin-based mud (GBM) or glycerol-based drilling fluid have shown the potential to be an alternative to OBM and SBM (Pomerleau, 2009).
2.1 Propane-1,2,3-triol
Glycerol is the simplest trihydric alcohol and it is known by propane-1,2,3-triol according to IUPAC (Figure 2.1). It is mainly composed of triglycerides, found in animal fat,
vegetable oil, or crude oil. Also known as glycerin, 1,2,3-propanotriol, trihydroxypropane, glyceritol or glycidic alcohol, glycerol first data of usage comes from the remote years of 2800 BCE, when it was isolated by heating fat mixed with ashes to produce soap (Hunt, 1999). However, it is considered to have been discovered by Carl W. Scheele, the first to isolate this compound, in 1779, during the heating of litharge (PbO) mixture prepared with olive oil (Quispe et al., 2013). In its pure form, glycerol is a viscous liquid, colorless, odorless, hygroscopic, and it has a sweet taste. In nature, glycerol is found in vegetables such as soybean, cotton, coconut, palm, and in animals, it is combined in forms of glycerin with fatty acids (Rivalti et al, 2008).
Figure 2. 1 – Glycerol (adapted from shutterstock website).
The term “glycerol” is used for the pure chemical compound propane-1,2,3-triol, while the term “glycerin” normally applies to purified commercial products with +95% of glycerol. They differ slightly in glycerol content and other characteristics such as smell, color, and traces of impurities (Knothe et. al, 2015). There are two ways to produce glycerol: natural glycerin, as a by-product of soap production (saponification) or fatty acid methyl esters such as biodiesel, and synthetic glycerol (Quispe et al., 2013). With the advent of the energy transition, driven by concern for climate change and a secure energy matrix, world production of biofuels has been increasing rapidly, including biodiesel (Levitt, 2017). From the 1970s until the year 2004, glycerin had a stable price between 1200 and 1800 US$/ton. Demand and production conditions were stable (Quispe et al., 2013). However, boosted by policies designed to cut the use of fossil fuels, such as the first EU biofuel directive in 2003, a surge in the production of biofuels in Europe and the US has been noticed (Levitt, 2017). As biodiesel production heavily increases, glycerol production increases which dumped onto a relatively stable market and, in 2005, the stable prices went into free fall, according to Figure 2.2. The volumes of glycerol were enormous and are growing (Quispe et al., 2013).
Figure 2. 2 – Global biodiesel production and crude glycerol price from 2003 to 2020 (OECD-FAO, 2015).
The scenario of a high level of production and not enough demand collapsed the prices, so, the glycerin market started looking for an alternative way to generate a high value-added product (Correa et al., 2017). Biodiesel is typically produced by the transesterification reaction of different triglycerides. Stimulated by a catalyst, the triglycerides react with alcohol, usually methanol or ethanol, producing biodiesel, methyl ester, ethyl ester, and glycerol (Quispe et. al, 2013). The transesterification reaction is the conversion of triglycerides to fatty acid methyl esters (FAME) (Ma et al., 2002). The authors explain that the overall process includes transesterification, recovery of unreacted methanol, separation of glycerol and FAME, recovery of glycerol as a high-grade coproduct, and purification of FAME, as shown in Figure 2.3.
Figure 2. 3 – Transesterification Process for Biodiesel (adapted from Rivaldi et at., 2008).
The proportion of production is 90% and 10% (w/w) for biodiesel and glycerol, respectively. In general, the crude glycerol produced has a dark brown color, see figure 2.3, and it contains varying amounts of soap, alcohol (methanol or ethanol), monoacylglycerol, diacylglycerol, glycerol oligomers, polymers and water difficult to remove, making purification an expensive process (Rivaldi et al., 2008; Pomerleau 2009; Soares et al., 2011).
2.2 Glycerin as Drilling Fluid
In November, 27th of 2007, Engineering Drilling Solutions INC., represented by Daniel
Guy Pomerleau, filed the patent application under the name “Glycerol Based Drilling Fluid”. His work was published in 2009 and the patent was expired in 2016 (Pomerleau, 2009). He showed in his studies that glycerin-based fluid, with combination of 95% to 20% of volume glycerol/water, it was capable to stabilizing a water-sensitive formation. For wells with open hole completion, for example, having a drilling fluid that resembles SBM and at the same time has less potential to damage the reservoir formation as WBM, it can save on operation time. Typically, in open hole completion, a SBM is used, because its better performance, until it reaches the formation of interest, then SBM is replaced by WBM, avoiding reservoir contamination, to finally drill the reservoir formation. Glycerin-based can be used throughout the entire operation. In addition, Pomerleau continues, glycerin-based, other than SBM, does not have a solvency effect of heavy hydrocarbons, for example, bitumen which can correspond from 30% to 100% of the layers being drilled resulting in a significant negative effect on formations. Numerous problems can occur due to the extreme adhesive nature of the bitumen, drillstrings and other tubulars can become coated, resulting in stuck pipe and undesired non-productive time (NPT) (Livanec et al., 2012).
However, walking through the path of drilling fluid studies, we can draw a brief review that address the interaction between drilling fluid, the well, and the formation revealing the challenging the a proper drilling fluid formulation must overcome, as it can be seen in Figure 2.5, and each one will be highlight next.
Figure 2. 5 – Brief chronology of drilling fluid studies.
1984 Cheatham Jr Hydration of swelling shale. 1995 Simpson et al. The importance to find an environmental ly friendly fluid system with similar OBM characteristics. 2003 Van Oort The physical and chemical stability of shales. 2011 Soares et al. Review new applications of glycerol and its derivatives in the industry. 2013 Marbun et al. Evaluated the use of glycerol as both SBM and WBM. 2017 Correa et al. Potential use of bioglyceri n as a basis for drilling fluids. 2018 Malgaresi et al. Glycerin based mud tests.
The ability to prevent the hydration of water-sensitive materials has a huge impact on the well stability. According to Caenn, et al. (2014), the reason behind well instability related to the interaction between drilling fluid and formation is hydration. Concern about well stability related to hydration of water-sensitive materials has been studied for years. Cheatham Jr. (1984) addressed that hydration of swelling shale was one of the most significant causes of wellbore instabilities. At that time, he pointed out that while OBM was more efficient with regard to hydration, although it could cause damage to the environment and be more expensive than WBM. Simpson et al (1995) also emphasized the importance, as opposed to the growth of restraint to OBM use, the need to find an environmentally friendly fluid system with similar OBM characteristics that could provide borehole stability, lubricity, and filtration control. Van Oort (2003) made a detailed study on the physical and chemical stability of shales. The author explained the complex links between transport processes, physical change, and chemical change, concluding that although the OBM/SBM is normally used to accomplish shale stabilization, today it is possible to accomplish it with economical and environmentally friendly WBM. Since glycerol is a polar substance, it is soluble in water and also has low interfacial tension, low conductivity, and higher density compared to water. Therefore, it has the potential for a lower weighting agent need, besides avoiding salt solubility and clay swelling, characteristic of paraffin and olefin-based drilling fluids (Corrêa et al., 2017).
Since biodiesel production generates high amounts of glycerol and derivatives, Soares et al. (2011) reviewed new industry applications for them as an alternative to disposal. They emphasized the use of glycerol as a drilling fluid once it is not necessary to use expensive glycerol purification processes as in the pharmaceutical and food industry. The authors synthesized, characterized and tested the performance of glycerol derivatives, more precisely glycerol esters, as additives for water-based drilling fluids and synthetic base fluids, such as n-paraffin and ester. The glycerol esters were used as lubricants for water-based fluids, as an emulsifier for n-paraffin based fluids, and as an anti-crystallizer for the ester base fluid. They studied the emulsion stability and lubricity of glycerol esters.
Marbun et al. (2013) evaluated the use of glycerol as both SBM and WBM additive in amounts of 0 to 15%. The authors evaluated the filtration properties, density, pH, rheology, lubricity, emulsion stability and its compatibility with additives used in water-based fluids and they compared with two other fluids, a biodiesel-based fluid, and a commercial mineral oil-based fluid. The authors concluded that the use of glycerol is effective and able to provide drilling fluid lubrication without compromising other technical properties required by API
standards. For the lubricity tests, the authors reiterated that the presence of glycerol as an additive in water-based fluid greatly improves the lubrication characteristic. The higher the amount of glycerol in the water-based fluid, the higher the lubricity, the higher the gel strength, the lower the thickness of the mudcake.
The permeability damage near the wellbore is caused by the invasion of the drilling fluids with particles. To avoid or mitigate the invasion, the drilling fluid formulation is designed in such a way that it can form a thin and a low-permeable filter cake on the wellbore wall (Malgaresi et al., 2018). The key factor of extent damage is the quality of external mudcake (Jiao et al., 2007). It is shown that particle invasion happens only during the mud spurt loss and the absence of external cake will reflect in a considerable decrease of permeability with the deep-bed particle invasion. Malgaresi et al. (2018) demonstrated through tests that glycerin-based fluid has lower filtrate invasion, faster cake stabilization, and higher return permeability when it is compared to water-based fluid. Additionally, the rheological and filtrate properties are in conformity with the API standards. Rheological models are critical in drilling fluid studies because they allow determining key parameters such as pressure drop, hole cleaning efficiency, and equivalent circulating density (ECD) (Dankwa et al., 2018).
Demirdal et al. (2009) demonstrated the importance of rheological characterization, especially when aspects like the drilling fluid density under temperature, pressure and depth variation are not taken into consideration, may implicate in serious problems. For example, the actual ECD may be higher than the calculated one, which will be used, overbalanced situation, and therefore, it can fracture the reservoir followed by a fluid loss, or the actual ECD can be lower than the calculated, underbalanced situation, which can lead to well control problems. Caen et al. (2014) pointed out that the drilling engineer controls the rheological properties of the drilling fluid to achieve the lowest cost of pumping, maximize the rate of penetration, efficiently transport the drilling cuttings, diminish the surge and swab pressure and the pressure to restart the circulation and minimize the well stability.
Correa et al. (2017) emphasize the importance of the analysis of the rheological behavior as a function of shear rate for drilling fluids characterization, once a very viscous fluid may affect the pumping from the storage tank to the drilling column and/or cause possible erosion in well walls that may compromise drilling stability. Caen et al. (2014) state that the main goal of the drilling engineer is to maintain the well stability. They showed that a proper design well will carry the cuttings with low viscosity drilling fluid whose process will be faster and fewer problems will occur. However, since the well diameter is uniform, as it
enlarges, the viscosity and gel forces must be increased in order to keep carrying the cuttings. But with higher viscosity and gel forces, the penetration rate decreases, the swab/surge pressures increase facilitating the increase in gas contamination. The authors complete the problem will be minimized with the usage of a fluid with a characteristic that allows fluids to acquire a semi-rigid state when at rest and fluidity when moving, thixotropy.
Quispe et al. (2013) reveal that glycerin at normal temperatures remains a viscous liquid even at 100% concentration without crystallizing and at low temperatures, concentrated glycerin solutions tend to super cool as high viscosity fluid. Solutions of glycerin (at different concentrations) has the tendency to lower viscosity and at low temperatures glycerin tends to super cool instead of crystallizing. Since it resists to freeze (crystallize), these solutions are usually used as antifreeze in cooling systems for example. Tables 2.1 and 2.2 show the physical and chemical properties of glycerol and the average viscosity of crude glycerol from the different feedstock, respectively.
Table 2. 1 – Physical and chemical properties of glycerol (adapted from Quispe, 2013).
Properties Unit Morrison Pagliaro and Rossi OECD-SIDS
Molecular formula - - C3H5(OH)3 C3H8O3
Molar mass g/mol 92.09 92.09382 92
Relative density kg/m3 1260 1261 1260
Viscosity Pa.s 1.41 1.5 1.41
Melting point °C 18 18.2 18
Boiling point (101.3 kPa) °C 290 290 290
Flash point °C 177 160 (closed cup) 160
Specific heat kJ/kg 2435 (25°C) - -
Heat of vaporization kJ/k-mol 82.12 - -
Thermal conductivity W/m.K 0.28 - -
Heat of formation kJ/mol 667.8 - -
Surface tension mN/m 63.4 64.0 63.4
pH (solution) - 7 - -
Table 2. 2 - Average viscosity and heat of combustion of crude glycerol from different feedstock (adapted from Quispe, 2013).
Feedstock Ida Gold Pack Gold Rapeseed Canola Soybean Crambe
Viscosity at 40°C (cP) 8.80 8.67 8.50 8.46 8.65 8.50
HHV1 (MJ/kg) 18.600 19.428 19.721 20.510 19.627 19.472
1HHV – Higher Heating Value
2.3 PVT Properties Studies of Drilling Fluids
According to The Code of USA Federal Regulations, 2016, well-control definition comprises all methods used to minimize the well potential to flow or kick and to keep control of the well in the event of flow or a kick. Those methods apply to different operations such as drilling, well-completion, well-workover, abandonment, and well-servicing operations. Including measures, practices, procedures, and equipment, well-control methods attempt to ensure safe and environmental protection of those operations as well as the installation, repair, maintenance, and operation of surface and subsea well-control equipment.
One key factor for well-control methods is the phase of the undesired influx and its solubility in the fluid of the ongoing operation. When the influx from the formation is in the liquid phase, its low compressibility cause, as soon as it enters the well, an increase in volume which would be recognized on the surface, allowing the operators to make a quick decision, such as closing the well safely. When the well is invaded by a gas and the operation fluid is water-based, the gas would occupy a small volume under the high-pressure conditions at the bottom of the well and as it flows to the surface, it would progressively expand. Its detection would be delayed, but it would not be as difficult as in the case of OBM/SBM, when the phenomenon of gas solubility would occur, especially in the organic phase (Kim, 2010).
The kick detection has fundamental importance because the sooner it is detected, the smaller the inflow volume into the well and the safer the conditions for kick removal (Santos, 2013). Concerning drilling operations, one way to optimize this detection time is to understand the fundamentals of gas solubilization in the drilling fluid, by developing a thermodynamic model that describes the behavior of the solution. Through the construction of phase diagrams, it would be feasible to make a prediction of the occurrence of this
phenomenon for the various pressure and temperature conditions (Silva. 2004). The studies that will be mentioned on this review can be seen in figure 2.6.
Thomas et al. (1982) performed experimental bubble pressure measurements for nine methane/diesel molar compositions, between 19% and 66%, at 38°C. Those experiments would be conducted in a variable volume equilibrium cell with an observation window. However, due to its abrasive nature, a stainless-steel cylinder was used instead of the equilibrium cell, not allowing visual verification of the phase behavior. By comparing the experimental data with those predicted by a computer program based on the Redlich-Kwong equation of state, differences in solubility were attributed to the presence of surfactants and dissolved solids in the drilling fluid. At low and moderate pressures, methane solubility was independent of temperature, while higher pressures caused increased solubility with increasing temperature. The authors showed that, the Redlich-Kwong equation did not adequately represent the experimental points, requiring an adjustment of the state equation parameters, using experimental data. After this modification, the improvement was perceptible. Their calculations indicated infinite solubility for pressures above a certain value, called critical mixture pressure. Figure 2.7 presents the data obtained and thermodynamic models performed through the Redlich-Kwong equation of state. The dashed line represents the results obtained using the equation of state and the solid line represents the results for the adjustment of the experimental data with the equation of state measurement behavior.
Figure 2. 7 - Brief chronology of PVT drilling fluid studies Thomas et al. (1982) • Bubble point • CH4/diesel • 19% to 66% • 38C • Redlich-Kwong Peter et al. (1990) • PVT study (density) • Diesel and Mineral oil • 0 to 15000 psi • 25.5 – 176,7C Berthezene et al. (1999) • PVT Study • Diesel, mineral, olefin, and ester • Peng-Robinson Silva (2004) • CH4/n-paraffin • CH4/ester • PVT cell • (177oC, 10000 psi) manual pump • T = 70oC and 90oC • yCH4= 15 – 75% Monteiro (2007) • CH4/n-paraffin emulsion with and without additives • PVT cell • (177oC, 10000 psi) • manual pump • T = 70, 90 and 150oC • yCH4= 1 – 15% Atolini (2008) • CH4/n-paraffin • CH4/n-paraffin emulsion • PVT cell • (200oC, 15000 psi) • automatic pump • T = 70 – 130oC • yCH4= 10 – 95% Kim (2010) • CH4/ester • CH4/ester emulsion • PVT cell • (200oC, 15000 psi) • automatic pump • T = 70 – 130oC • yCH4= 10 – 90% Lima Neto (2014) • CO2/n-paraffin • CO2/n-paraffin emulsion • PVT cell (200oC,15000 psi) • automatic pump • T = 40 – 80oC |yCO2= 10 – 50% Policarpo (2014) • DIFFUSION • CH4/n-paraffin • CO2/n-paraffin • T = 60-120oC • yCH4 = 7-95% MARQUES (2016) • CH4/olefin • PVT cell • (200oC, 15000 psi) • automatic pump • T = 25 – 80oC • yCH4= 30, 40 and 50%
Peters et al. (1990) conducted PVT tests for diesel and two mineral oil-based drilling fluids within a range of 0 to 103 MPa and 25.5C to 176.7C. With an existing compositional material-balance model, the measured densities were used to predict the known densities. They also measured the densities considering elevated pressures and temperatures and compared them with the predicted values. The results revealed to be in agreement between measured and predicted densities. They also used the experimental density data to predict downhole densities and static wellbore pressures for the oil-based fluids.
Berthezene et al. (1999) studied the drilling fluids that were being developed in the late 90s, including the PVT behavior of those fluids with methane at 90C. Four different fluids were used: diesel, mineral, olefin and vegetable ester. Their saturation pressure measurements were taken up to 35 MPa and these results were used to adjust the Peng-Robinson equation of state. As shown in Figure 2.8, in the range of moderate pressures up to 35 MPa (350 bar), the solubility of four fluids have comparable trend. Conditions of high pressures were extrapolated, predicting critical points of mineral oil, olefin and diesel oil from 50 to 70 MPa (500 to 700 bar). However, for the ester, there is no prediction of the critical point at pressures below 100 MPa at the test temperature, according to the modeling. Since there is an ester group in the latter, different from mineral, olefin and diesel oil, it causes a polarity of the molecule and possibly reduces the total solubility (Atolini, 2008).
Figure 2. 8 – Phase envelope of methane with 4 oil bases, measured and calculated at 90C (Berthezene et al., 1999).
Silva (2004) investigated the behavior of gas solubility in synthetic-based drilling fluids. The work involved the PVT characterization of two organic liquids (n-paraffin and
ester) used in deep and ultra-deep-water drilling fluids. Experimental measurements of the thermodynamic properties of methane-liquid mixtures, such as bubble pressure, solubility, oil formation volume factor, gas volume formation factor and specific mass of the liquid, were made at temperatures of 70°C and 90°C. The tests were performed in a blind PVT equipment, and for n-paraffin, molar methane concentration from 16% to 73% and pressures up to 55 Mpa were tested. Ester experiments were performed with 18 to 74% molar methane fraction and pressure up to 70 MPa at the same temperatures. The results showed that methane solubility was much higher in the mixture with n-paraffin than with ester.
Monteiro (2007) evaluated the phase behavior of CH4/n-paraffin mixtures, analyzing the influence of drilling fluid additives with the addition of additive to n-paraffin. It was found that the solubility of methane in the brine composing the emulsion with n-paraffin was negligible. He used the same PVT equipment as Silva (2004), under conditions of 70, 90 and 150C and methane molar fractions from 1 to 15%. From his experimental data, he proposed relevant solubility correlations applied to in well control work using synthetic fluids.
Atolini (2008) made a complete study of the PVT behavior of CH4/n-paraffin, for 10 to 95% molar gas compositions at high temperatures of 70 to 130C. In addition, the author also analyzed the methane / emulsion system, with two emulsion compositions, one with 60% n-paraffin, in volume and the other, with 70%, also varying the gas fraction and temperature. The PVT system used in his studies was a cell with capacity of to 200C and 103 Mpa, a system whose pressures are controlled by an automatic pump, allowing the visualization of fluids under process conditions.
Kim (2010) performed studies of CH4/ester mixtures and ester emulsions in the same
equipment used by Atolini (2008). The temperature range and molar gas fractions evaluated were also similar to those of Atolini (2008), 70 to 130C and 10 to 90% methane, respectively.
Policarpo (2014) evaluated the diffusive behavior of CH4/n-paraffin and CO2/n-paraffin mixtures at temperatures from 60 to 120C and methane fractions from 7 to 95%. The author proposed a correlation for calculating the diffusivity of these mixtures.
Lima Neto (2014) conducted PVT experimental studies for the CO2/n-paraffin mixture
at temperatures from 40 to 80C and molar fractions from 10 to 50% CO2. He found that CO2
is more soluble in n-paraffin than methane when under the same pressure and temperature conditions.
More recently, Marques (2016) conducted studies with olefins and methane in low gas fractions (30 to 50%) and temperatures of 25 to 80C. The researcher also used the same PVT equipment as Atolini (2008), Kim (2010), Policarpo (2014) and Lima Neto (2014), which will be used in this project.
3. EXPERIMENTAL APPARATUS AND PROCEDURE
3.1 PVT Experimental Apparatus
The experimental apparatus consists of a model Z16 – Schlumberger PVT system, which is composed of a PVT cell (100 cm3, 103 MPa), an automatic pump (500 cm3,
138 MPa), and data acquisition system. Figures 3.1 and 3.2 present an overview and layout of the apparatus, respectively. The highlighted main components are detailed below.
Figure 3. 1 – Experimental apparatus.
3.1.1 PVT Cell
The PVT cell is precision manufactured laboratory equipment designed specifically for the measurement of fluid phase behavior properties at controlled temperatures and pressures, Figure 3.3, with a volume capacity of 100 cm3 and an operating pressure of limit 103 MPa.
Figure 3. 3 – PVT Cell
The cell is installed in a chamber with an air bath heating and cooling system that allows temperatures from 15°C to 200°C. It is supported by a horizontal axis that allows its rotation by activating an external control. This control has a key that indicates the direction of rotation and a knob to control the speed of movement.
The sample, the fluid sample under study, is confined within a clear glass tube sealed at its ends by Viton rings. The piston, also equipped with Teflon rings, isolates the fluid sample from the hydraulic fluid used to exert pressure on it. The hydraulic fluid is an innocuous and transparent oil called Conosol. It also fills the space surrounding the glass tube and the PVT cell, annular space, in order to exert the same pressure inside and outside along the glass tube. This equal pressure is maintained through an overburden valve that must always be open. The
closed valve causes a pressure differential during operations that the glass tube may not support.
The cell has a window in front of the glass tube and one behind. Both the same size and height equal to the height of the glass tube. The windows, the glass tube and the transparency of the hydraulic fluid allow the light to come through from two lamps positioned behind the cell. It is possible to visualize the sample during the tests. At the ends of the cell, it is installed a magnetic mixer that provides rigorous agitation of the entire fluid sample. Its use enables the reduction of operating time as it increases the speed of stabilization of the phase balance of the sample. This agitator is driven by a controller that provides motor speed variation up to a maximum speed of 2500 rpm. The direction of rotation can also be changed.
3.1.2 Pump
The high-pressure positive displacement pump is designed to accurately meter, feed or proportionately displace fluids under high-pressure conditions. Its maximum operating pressure is 137 MPa, total pump volume of 500 cm3, and volume resolution of 0.01 cm3 (Figure 3.4). It uses a machined piston of precise diameter to displace a fluid that is confined within a cylinder. To prevent leak, there is a system of high-pressure seals that are held firmly within the cylinder end. Therefore, the displaced fluid volume is proportional to the calibrated length of the piston inserted into the cylinder.
Although the measurement of the displacement can be read at the software in the computer connected to the pump, there is also a system of circular scales that are calibrated to measure volumetric displacement in units of cubic centimeters. A linear scale mounted on the top of the pump is a coarse visual reference for displaced volume. A Vernier scale, circumscribing the ball screw on the pump gear housing, provides fractional measurement.
Pump displacement can be controlled by the motor gear unit which is controlled by software called DBR Pump Control System. This software enables the pump to be driven in two different modes: pressure and volume, with timed data acquisition. However, manual volume displacement is also possible by the handwheels. To use them, it is needed to disengage the worm drive from the ball nut by retracting the spring-loaded detent pin located on the large hand wheel near the Vernier scale and rotate the detent pin knob by 90 degrees.
The large diameter handwheel allows for quick retraction of the piston when re-setting the pump, displacement of large volumes of fluids under relatively low pressures and provides a method to achieve a rapid pressure increase from low to mid-range pressures.
Figure 3. 4 – High pressure positive displacement pump.
3.1.3 Data Acquisition System
The PVT Data Acquisition System provides instrument control, data capture, and data display for the PVT system. It supports all the standard instrumentation in the PVT system including pressure, temperature, and volume measurements, and provides full control of the pump.
The CCD Level Measurement System, Long Focus, is used to quickly and accurately measure fluid height and volume in the cell. It is an essential component in data acquisition during experiments. This system includes a high-resolution color CCD camera, shown in Figure 3.5, equipped with a zoom lens and extension tube assembly to act as a long-distance microscope. The viewing area is approximately 2 cm by 2.8 cm in size. This camera is
coupled to a vertical displacement motorized mechanical component with a high precision linear encoder.
Figure 3. 5 – High-resolution color CCD camera.
The vertical shift system controller enables two speeds, one faster and one slower, for fine adjustments. The position (height) indicator can be reset to allow to reference measurements. In addition to direct control through this controller, the camera position can also be controlled via the PVT Data Acquisition System graphical interface. A high-resolution color monitor, also shown in Figure 3.6, is used to view the camera image.
3.2 Rheology Measurement
The rheology analyses were performed for all GBM and the distilled water was used for reference. For all tests, two rounds of tests were run for each fluid at isothermal condition, from 20 to 80C. The equipment used was the rotational rheometer Haake Mars III, (Thermo Fischer Scientific 2008a), as shown in Figure 3.7. The equipment took about 11 ml of the fluid sample, which is the volume corresponding to the meniscus in the cylindrical sample holder, and a new sample was used for each test performed. In the analyses, the samples were subjected to a shear rate (γ) ranging from 0.1 to 1000 s-1, typical values for most rheometers
(Barnes, 2000). For each imposed shear rate, the equipment records the shear stress (τ), viscosity (μ) and temperature (T), summing a total of 20 points in each analysis.
Figure 3. 7 – Rotational Rheometer Haake Mars III.
3.3 Density Measurement
Specific mass or density was measured at ambient pressure conditions and temperatures ranging from 25 to 80°C. The Anton Paar DMATM 4200M benchtop digital densimeter (Figure 3.8), is a modern model equipped with oscillating U-tube consisting of Hastelloy C-276 instead of a glass U-tube as previous models. The equipment is capable of measuring at temperatures between -10 and 200°C, at pressures from 0 to 50 MPa, and densities between 0 and 3 g/cm3, with a resolution of 10-5 cm3. To ensure accurate numbers, each experiment was
Computer Ethernet Controller Refrigerated bath Rheometer
