Hydrate Prevention

HYDRATE PREVENTION IN SUBSEA NATURAL GAS PRODUCTION

TPG4510 Petroleum Production Specialization Project

by Moses Gideon Akpabio

Faculty of science and Technology Institute of petroleum Technology (IPT) Department of Petroleum Engineering and Applied Geophysics

NTNU Norwegian University of Science and Technology

JULY, 2012

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Acknowledgement This piece of work would not have been possible without the help and contributions of others. I hereby seize this opportunity to appreciate these people for their assistance whenever I found myself in doubt of what to do and how to do it. My profound gratitude goes to my supervisor, Professor Jon Steinar Gudmundsson for his understanding and assistance on defining this project work, his guidance, and all useful links he sent to me while here in Nigeria that have make this final result possible. I also appreciate the way he accepted me as his student, his advice and answers to all of my questions. I equally acknowledge the support of Associate Professor Pal Skalle as well as the Norwegian government for sponsoring the EnPE/NORAD programme. I also appreciate my friends and colleagues, especially Mr. Samson Imoh, and others, whose suggestions and inputs have enhanced my motivation in finishing this project work. However, I acknowledge the works of several authors as well through which I have gained a lot of new ideas for this project work. I deeply appreciate the creator of the universe for His mercies, love and for this wonderful opportunity. And, my Parent and siblings are well acknowledged for their respective contributions to my life.

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Abstract Subsea production of oil and gas is always faced with the potential problem of hydrates formation which causes pipeline blockage, damage of pipeline fittings, and other related problems. A reliable method that has the ability to predict hydrate formation conditions during the production process, and transmission is thus needed. It is important to ensure safe operations. In this work, water concentration estimation for the conditions prevailing at the reservoir, the wellhead and the receiving terminal on land are evaluated analytically based on theoretical approach. As an example, a natural gas stream from Nigeria with pipeline as a transmission medium is used. The temperature profile and pressure profile along this pipeline have also been used as an input in the evaluation of hydrate formation. Also, a hydrate inhibition strategy with MEG is considered. Results show that the flow is within the hydrates forming region, since the temperature is below 20 oC and pressure, above 100 bara. Water concentration estimation provides useful information which can assist in prevention of hydrate formation as gas flows through a pipeline. The temperature profile and pressure profile also provide useful information for the management or controlled of hydrates formation as the temperature and pressure data can indicate the thermodynamic conditions that favours hydrates formation.

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Table of Contents Title

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Acknowledgement. .

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Abstract.

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Table of Contents.

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List of Tables. .

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List of Figures. .

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1. Introduction.

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2. Natural Gas: A Closer Look. . 2.1 Brief History of Natural Gas. .

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3. Natural Gas Hydrate. . . . . . . 3.1 Structures of Gas Hydrates. . . . . . 3.2 Conditions Necessary for Formation of Hydrates. . . 3.3 Gas Hydrate Prevention. . . . . . 3.3.1 Hydrates Prevention with Inhibitors. . . . 3.3.2 Selection of Hydrate Prevention and Remediation Strategies. 3.4 Hydrates Prevention Using MEG. . . . .

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4. Water Content of Natural Gas.

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5. Empirical Correlations and Calculation Methods.

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5.1 Water Content of gas stream . . 5.2 Temperature Profile. . . . 5.2.1 Necessary Equations and Variables. 5.2.1.1 Heat Capacity Estimation. . 5.2.1.2 Mass Rate. . . . 5.3 Pressure Profile. . . . 5.3.1 Necessary Parameters and Equations. 5.3.1.1 Reynolds Numbers. . . 5.3.1.2 Density. . . . 5.3.1.3 Velocity. . . . 5.3.1.4 Viscosity. . . . 5.3.1.5 Gas Compressibility Factor (Z). 5.3.1.6 Friction factor. . . 5.4 MEG Estimation. . . .

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6.1 Water Content of Natural Gas at different Conditions. . 6.2 Temperature Profile. . . . . .

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6. Result and Discussion.

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6.3 Pressure Profile. . . . 6.4 Hydrate Inhibition using MEG. .

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7. Discussion of Project Work 7.1 Quality of Model. . . 7.2 Quality of Input Data and Results. 7.3 Potential Improvements. .

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8. Conclusion. .

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Nomenclatures.

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References.

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Appendix A: Tables & Figures.

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Appendix B: Calculation Procedures.

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List of Tables Table 1: Typical Natural Gas Components. . . . . . Table 2: Three common hydrate unit crystal structures. . . . Table 3: Summary of Applications, Benefits & Limitations of Chemical Inhibitors. Table 4: Water Content of gas at different conditions. . . . Table A1: Sour gas correction factor constants. . . . . Table A2: Constants in LGE equation. . . . . . . Table A3: Natural Gas Reservoir, Production & Pipeline Parameters. . Table A4: Natural Gas Stream Composition from Nigeria, with modification. Table A5: Temperature Profile Data. . . . . . . Table A6: Pressure Profile Data. . . . . . .

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List of Figures Figure 1: Natural Gas Typical Molecule. . . . . . . Figure 2: Hydrate Plug Removed from a Gas Pipeline. . . . . Figure 3: Host molecules (water) and guests (Gas). . . . . . Figure 4: Schematics of Structure I, II and H Gas Hydrates. . . . . Figure 5: Phase Diagram Showing the Conditions under which Hydrates form. . Figure 6: Conceptual representation of hydrate formation in an oil-dominated system. Figure 7: MEG Reclamation Process Schematics. . . . . . Figure 8: Temperature variation along pipeline. . . . . . Figure 9: Steady-State flow (pressure) in gas pipeline. . . . . Figure 10: Steady-State Temperature Profile. . . . . . Figure 11: Steady-State Pressure Profile. . . . . . . Figure A1: Water contents of natural gases. . . . . . . Figure A2: Pressure-temperature Curves for Predicting Hydrate Formation Temperature. . . . . . . . . . Figure A3: Natural Gas Heat Capacity of 0.60 and 0.65 Specific Gravity. . .

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1. Introduction Natural gas is rapidly growing in global importance both as a primary energy source and as a feedstock for the downstream industry. The increase of natural gas in the energy matrix all over the world has posed a strong demand on offshore exploration and production. Natural gas consumption has constantly continued to increase from 50 % of the oil consumption in 1950 to 98 % in 1998 (Chapoy 2004). This growth is being driven by a number of economical, ecological and technological factors together with an overall increasing energy demand because it is environmentally cleaner than oil and coal. Natural gas demand is increasing steadily and considering pipeline among other means of transporting oil and gas, there is guaranteed delivery from the wellhead to processing plant and from there to the consumers and which also assures lower maintenance costs. It is therefore important to operate an offshore pipeline system free of hydrate formation risks. However, it is worthy to note that subsea pipelines represent at least 25 % of the total project cost and this is one of the reasons for the flow assurance studies (Nava et al. 2011). The past decade has seen the oil and gas industry moving towards deep-water exploration and production, with over 10,000 feet of water depth (Mehta et al. 2001), where pressures and temperatures are ideal for hydrate formation. This has brought new challenges for hydrate prevention in transportation of natural gas in subsea environment. Hydrate formation in offshore pipelines is a major problem that arises due to temperature drop and other thermodynamic changes as hydrocarbons are produced. As temperature drops or decreases, the solubility of water in gas decreases and the water vapour condense. The precipitated water molecule causes hydrate to form with hydrocarbon molecules such as methane. The formation of hydrates can lead to clogging of pipeline, higher pressure losses, flow rate reduction, and other problems. The removal of hydrate plugs in subsea production systems as well as transmission systems poses safety concern and can lead to loss of time and costly repair work. For these reasons, the formation of hydrates in subsea gas transmission pipelines should be prevented effectively and economically to guarantee that the pipeline operates normally.

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The main objective of this project is to study flow assurance of a natural gas produced from a subsea environment. A pipeline transmission system of natural gas stream from subsea to shore (receiving terminal on land) is considered, using a natural gas stream composition from Nigeria as an example. In order to avoid hydrate formation in the pipeline system during transmission, my focus is on analyzing the temperature profile and pressure profile in a steady-state production conditions along the pipeline. These will provide information on temperature and pressure data along the pipeline as well as indicating if hydrates will form. Water vapour content of natural gas is also analyzed for conditions prevailing at the reservoir, wellhead, and at the receiving terminal. Hydrates formation prevention with Mono-Ethylene-Glycol (MEG), and an inhibitor’s rate required to prevent hydrates formation are also analyzed. The inhibitor is to reduce the dew point temperature of water vapour in the gas flow below operating temperature and thus, decreasing the risk of hydrate formation. These will be computed analytically based on the theoretical approach. This project is a case study based on a specific steady-state defined production case. The production data is provided in the Appendix, Table A3. The results will be analysed to identify if the pipeline has the potentials of forming hydrates as the temperature and pressure drop along the pipeline and to analyse the inhibitor’s that could be used to prevent hydrates from blocking the pipeline.

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2. Natural Gas: A Closer Look Natural gas is a non-renewable resource that is expected to be widely expanded in the decades to come. It is considered a very safe energy source when transported, stored and used. It is a mixture consisting mainly (70 - 95 %) of methane (CH4, a covalent bond composed of one carbon atom and four hydrogen atoms), as shown in the Figure 1. It also contains other gaseous hydrocarbons such as ethane (C2H6), propane (C3H8), normal butane (n-C4H10), isobutane (i-C4H10), and pentane (C5H12), among other higher molecular weight hydrocarbons (Sanchez 2010).

Figure 1: Natural Gas Typical Molecule: Models of molecules of oxygen (O2), water (H2O), methane (CH4) and carbon dioxide (CO2) (Sanchez 2010).

Natural gas also contains impurities or contaminants that have to be removed before it can be used as a consumer fuel after its extraction from the reservoir. These impurities include acid gases, such as hydrogen sulfide (H2S), carbon dioxide (CO2), mercaptans (methanethiol – CH3SH, and ethanethiol – C2H5SH), nitrogen (N2), helium (He), and water vapor (H20). Sometimes, mercaptans are kept or added for safety reasons (Sanchez 2010). However, a typical composition of natural gas is given in Table 1.

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Table 1: Typical Natural Gas Components, (Chapoy 2004). Hydrocarbons

Non - Hydrocarbons

Components Methane Ethane Propane

Mole % 70 - 98 1 -10 Trace - 5

Components nitrogen Carbon dioxide Hydrogen sulphide

Mole % Trace - 15 Trace - 20 Trace - 20

Butane

Trace - 2

Helium

Up to 5 (non usually)

Pentane

Trace - 1

Hexane

Trace - 0.5

Heptane+

Trace

In the reservoir, oil and natural gas normally coexist with water. Water comes as the wetted phase and from the sub-adjacent aquifer. The presence of water also causes crystallization of salts after hydration due to salt concentration increase (when water is consumed). Furthermore, when gas is produced offshore, the separation of liquid fractions and the removal of water are not always carried out before the production flow is sent into pipelines. Consequently, the unprocessed well gas stream coming from a production field can contain water and light hydrocarbon molecules (methane, ethane, propane and other components). Given the correct temperature and pressure conditions (particularly large temperature gradients which leads to higher pressure), can lead to hydrate formation during transport through pipelines.

2.1 Brief History of Natural Gas The history of natural gas can be traced back to the ancient Mesopotamia, or the cradle of civilization that is known today as the Middle East. Natural gas has been observed since ancient times (Ingersoll 1996). However, it was until a few centuries ago that countries such as Great Britain, China, and USA, among others, started using natural gas as a means of supplementing their need for energy (Mokhatab et al. 2006). Moreover, the construction of a sustainable gas infrastructure, including storage, preprocessing and transport facilities allows natural gas to become commercially available throughout the world (Sanchez 2010). According to Mokhatab et al. (2006), Chinese drilled the first known natural gas well in 211 B.C. A few centuries later (around 500 B.C.), they employed crude bamboos as a means to 4

transport natural gas. In Europe, even though the British discovered natural gas in the middle of the 17th century, it was until the late 18th century (around 1785) that they started trading natural gas obtained from coal seams for lighting of houses and streets (Rojey et al. 1994). An intriguing factor that caused a faster expansion of the use of natural gas around the world in the last decade of the 19th century was the fact that many cities began replacing their gas lamps with electric lamps. Thus, the gas industry was required to look for new markets, perhaps far away from their usual customers (Sanchez 2010). Natural gas had been clearly extinguished by electricity. However, at that time the real problem was certainly the lack of a pipeline infrastructure to transport and distribute natural gas, as well as the lack of facilities to store it (Chapoy 2004).

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3. Natural Gas Hydrate Gas hydrates were first identified in 1810 by Sir Humphrey Davy and their composition established by Faraday, Koh (2002). They are crystalline compounds formed by chemical combination of natural gas and water under pressure and temperature considerably above the freezing point of water (Sloan 1998). Hammerschmidt, in 1934 determined that the plugging of natural gas pipelines was not due to ice formation but to formation of clathrate hydrates of natural gas (Gaillard et al. 1999). They had it that, this discovery was the determining factor in causing a more pragmatic interest from oil and gas companies. As said earlier, natural gas hydrate in oil and gas pipelines may block the pipelines, facilities and instruments and cause flow and pressure monitoring errors, reducing gas transportation volume, increasing pipeline pressure differences and damaging pipe fittings, as shown in Figure 2.

Figure 2: Hydrate Plug Removed from a Gas Pipeline, Zarinabadi et al. 2011.

3.1 Structures of Gas Hydrates The structures of the crystals fall into the class of clathrates with the water molecules forming a hydrogen-bonded cage-like structure which is stabilized by ‘guest’ molecules 6

located within the lattice, Makogon (1997) and Sloan (1998). Gas hydrates which are crystalline ice-like solids are formed from water and a range of lower molecular weight molecules, typically methane, ethane, and propane. The water molecules are referred to as the ‘host molecules’ and the other compounds which stabilize the crystal are called, the ‘guest molecules’. The hydrate crystals have complex, three-dimensional structures in which the water molecules form a cage and the guest molecules are entrapped in the cages as shown in Figure 3.

Figure 3: Host molecules (water) and guests (Gas), Zarinabadi et al. 2011.

There are three known hydrate structures referred to as structures I, II and H (abbreviated as sI, sII and sH) as contained in Pickering et al. 2001. The schematics of the three different structures are presented in Figure 4.

Figure 4: Schematics of Structure I, II, and H Gas Hydrates (source: www.feesa.net).

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Structure I hydrates contain 46 water molecules per 8 gas molecules giving a hydrate number of 5.75. The water molecules form two small dodecahedral voids and six large tetradecahedral voids. The sizes of the voids are relatively small meaning that the guest molecules are restricted in size to essentially methane and ethane (Pickering et al. 2001). Structure II hydrates contains 136 water molecules per 24 gas molecules giving a hydrate number of 5.67. The water molecules form 16 small dodecahedral voids and 8 large hexakaidecahedral voids. The larger voids are able to accommodate molecules including propane, isobutane, cyclopentane, benzene and others. However, while the larger cavities can accommodate larger molecules, the structure is only stable if small ‘help’ molecules are available to fill the smaller lattice cavities (Pickering et al. 2001). Structure H hydrates contains 34 water molecules for every 6 gas molecules giving a hydrate number of 5.67. The structure has three cavity sizes with the largest cavity able to accommodate larger molecules than both sI and sII. Once again, stability is only possible in the presence of smaller ‘help’ molecules such as methane or nitrogen (Pickering et al. 2001). Table 2 lists the properties of the three common unit crystals.

Table 2: The three common hydrates unit crystal structures. Nomenclature: 51264 indicate a water

cage composed of 12 pentagonal and four hexagonal faces. The numbers in squares indicate the number of cage types. For example, the structure I unit crystal is composed of two 5 12 cages, six 51262 cages and 46 water molecules. (Sloan Jr., 2003)

Hydrate crystal structure

I

Cavity

Small

Large

Small

Large

Small

512

51262

512

51262

512

6

16

8

4.33

3.91

4.73

24

20

Description Number of cavities per unit cell Average cavity radius (Å)

II

2 3.95

Coordination number

20

Number of waters per unit cell

46

H

136

28

medium

Large

435663

51262

3

2

1

3.91

4.06

5.71

20

20

36

34

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3.2 Conditions Necessary for Formation of Hydrates There are three major conditions necessary for hydrates formation (Zarinabadi et al. 2011). These include:   

Water as the liquid phase. Hydrate formers. These are small gas molecules such as methane, ethane, and propane. The right combination of temperature and pressure. Hydrate formation is favoured by low temperatures and high pressures typically 20°C and 100 bara.

Figure 5 presents a hydrate formation diagram in the pressure-temperature plane. The right hand region covers pressures and temperatures at which hydrates are thermodynamically unstable and is therefore ‘hydrate free’ as indicated. In the ‘hydrates region’, the degree of sub-cooling is sufficient such that hydrates form spontaneously, Estefen et al. 2005.

Figure 5: Phase Diagram Showing the Conditions under which Hydrates will form (Estefen et al. 2005).

Gas hydrates form in the water phase from gas molecules dissolved in that phase. Consequently, H2S and CO2 increase the temperature at which hydrates will form since they are more soluble in water than most hydrocarbons. Turbulence producing conditions (for

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example: orifice meters, reduced port valves) enhance the formation of hydrates during flow. However, hydrates also form under static conditions. Factors that contribute to the initiation of hydrate formation include: •

Degree of sub-cooling – hydrates may not begin to form immediately upon reaching the hydrate point. As much as 5°C to 10°C of sub-cooling is needed to form the first seed crystals of hydrates;

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Presence of artificial nucleation sites – rest, scale, sand, and

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Degree of mixing – system geometry and flow regime (CAPP 2007)

Furthermore, once crystallization has begun, time is needed for the crystals to agglomerate (clump) and actually block the flow (CAPP 2007). In other word, hydrates formation is a transient process. Also, the exact hydrate formation point depends on the composition of the fluids involved; gas composition and water as well as brine composition. In Figure 6, the conceptual representation of hydrate formation is shown schematically as temperature drops along a pipeline with time in oil dominated system, though this project focuses on gas system. It starts with a shell and then grows up to a hydrate plug (Sloan et al. 2009).

Figure 6: Conceptual representation of hydrate formation in an oil-dominated system. Sloan et al. 2009.

3.3 Gas Hydrate Prevention ‘’Hydrates can be prevented and should not be accepted as normal operating routine. A hydrate prevention program is more effective than remedial removal measures (CAPP 2007)’’. The industry has developed several techniques to prevent the formation of gas hydrates. These methods together with design considerations are extensively discussed in the literature: Hammerschmidt (1939); Campbell (1998); Makogon (1981); Nielsen and Bucklin 10

(1983); Robinson and Ng (1986); and Ng et al. (1987). The following are the thermodynamic ways to prevent the hydrate formation: 1. Reducing the water concentration from the system. 2. Operating at temperatures above the hydrate-formation temperature for a given pressure by insulating the pipelines or applying heat. 3. Operating at pressures below the hydrate-formation pressure for a fixed temperature. 4. Adding inhibitors such as salts, methanol, and glycols to inhibit the hydrate formation conditions and shift the equilibrium curve to higher pressure and lower temperature.

3.3.1 Hydrates Prevention with Inhibitors Inhibitors are added into processing lines to inhibit the formation of hydrates. There are two kinds of inhibitors: thermodynamic hydrate inhibitors (THI), and low-dosage hydrate inhibitors (LDHI), Paez et al. 2001. The thermodynamic hydrate inhibitors (THIs) have been used for a long time in the industry and they act as antifreeze. The main benefits of the thermodynamic hydrate inhibitors (THIs) are their effectiveness, reliability (provided sufficient quantities are injected) and proven track-records (Pickering et al. 2001). However, he observed that these benefits are outweighed by significant limitations, including high volumes, high associated costs (both CAPEX and OPEX), toxicity and flammability. He added that, they are harmful to the environment and significant disposal into the environment is as well prohibited. Low-dosage hydrate inhibitors have recently been developed and their usage modifies the rheology of the system rather than changing its thermodynamic states. These inhibitors work at low concentrations, lower than or equal to one (1) weight percent; therefore, the use of this technique reduces the environmental concerns and since no regeneration units are required, it results in reduction of capital cost, Pickering et al. 2001. The low-dosage hydrate inhibitor is divided into kinetic hydrate inhibitors (KHIs), and anti-agglomerants (AAs). The kinetic inhibitors (KHIs) are commonly water-soluble polymers which delays the nucleation and growth of hydrate crystals. Kinetic hydrate inhibitors are injected in much

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smaller quantities compared to thermodynamic inhibitors and therefore offer significant potential costs savings, depending on the pricing policies of major chemical suppliers (Pickering et al. 2001). They are also typically non-toxic and environmentally friendly. In addition, the effectiveness of KHIs appears to be system specific, meaning that testing programmes are required prior to implementation. Unfortunately, adequate testing can require appreciable quantities of production fluids which may not be available, particularly for new field developments. Furthermore, KHIs can interact with other chemical inhibitors (for example corrosion inhibitors) and testing programmes need to account for this also (Graham et al. 2001). They concluded that there are no established models for predicting the effectiveness of KHIs which presents difficulties for field developers considering the application of these chemicals. Anti-agglomerants are usually surfactants and miscible in both hydrocarbon and water, so they impede the agglomeration of hydrate crystals for a period of time without interfering with crystal formation (Sharareh 2005). The benefits and limitations of Anti-Agglomerants (AAs) are largely similar to those for KHIs, although AAs do not have the same sub-cooling limitations. However, there is uncertainty about the effectiveness of AAs under shutdown or low flow rate conditions and it is postulated that agglomeration may still proceed. In addition, the one major limitation of AAs compared to KHIs or THIs is that they are limited to lower water-cuts due the requirement for a continuous hydrocarbon liquid phase. Finally, compared to both THIs and KHIs, Anti-Agglomerants lacks field application experience, Pickering et al. 2001.

3.3.2 Selection of Hydrate Prevention and Remediation Strategies The selection of hydrate mitigation and remediation strategies is based on technical and economic considerations and the decision is not always clear-cut, Pickering et al. 2001. In their report, for example, they cited that, in a deepwater development with a significantly higher reserves base, the operator may elect for a higher cost strategy (example: electrical heating) in order to minimize risks. In Table 2, a summary of the applications, benefits and limitations of the three classes of chemical inhibitors are presented.

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Table 3: Summary of Applications, Benefits & Limitations of Chemical Inhibitors (Pickering et al. 2001)

Thermodynamic Hydrate Inhibitors

Kinetic Hydrate Inhibitors

Anti-Agglomerants Inhibitors

1. Multiphase 2. Gas & Condensate 3. Crude oil?

1. Multiphase 2. Condensate 3. Crude oil

1. 2. 3. 4. 5.

1. 2. 3. 4. 5.

Applications 1. Multiphase 2. Gas & Condensate 3. Crude oil Benefits 1. 2. 3. 4.

Robust & effective Well understood Predictive Proven track-record

Lower OPEX/CAPEX Lower volume (<1wt. %) Environmentally friendly Non toxic Tested in gas system

Lower OPEX/CAPEX Lower volume (<1wt. %) Environmentally friendly Non toxic Wide range of subcooling

Limitations 1. 2. 3. 4. 5. 6.

Higher OPEX/CAPEX High volumes (10-60wt. %) Toxic / hazardous Environmentally harmful Volatile – losses to vapour ‘Salting out’

1. 2. 3. 4. 5. 6.

Limited subcooling (<10%) Time dependency Shutdowns System specific – testing Compatibility Precipitation at higher temperature 7. Limited exp in gas systems 8. No predictive models

1. Time dependency? 2. Shutdowns? 3. Restricted to lower water cuts 4. System specific – testing 5. Compatibility 6. Limited experience 7. No predictive models

3.4 Hydrates Prevention Using MEG A typical hydrate mitigation strategy is based on continuous injection of a thermodynamic hydrate inhibitor (typically mono ethylene glycol [MEG]) with little or no insulation of the subsea system. Today, Mono Ethylene Glycol is the state of the art hydrate control method (Estefen et al. 2005). They also had it that besides preventing hydrates, MEG reduces the corrosion rate in the carbon steel pipelines normally used and is well suited as carrier of corrosion inhibitors and pH-stabilizers. Glycol is also considered to be regeneratable and considered being environmentally friendly, because of its chemical properties and the use within a closed loop system where the losses are relatively small (Estefen et al. 2005). 13

The main benefits of a MEG solution include: • • • • • •

Reliable solution; Closed loop; Corrosion protective; No gas plant or refinery contamination; Environmentally friendly, non-toxic, non-flammable; Qualified technology.

In a closed loop system, Rich MEG arriving at the production unit must be regenerated to Lean MEG quality, 90-95 weight % MEG, before being re-injected at the subsea producers (Estefen et al. 2005). The full reclamation of MEG process is illustrated in Figure 7.

Figure 7: MEG Reclamation Process Schematics. (Estefen et al. 2005)

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4. Water Content of Natural Gas Water is associated with natural gas from the reservoir, through production and processing and is a major concern in transmission of natural gas. Natural gas leaving a gas reservoir is saturated with water, and when it expands at wellheads or into separators, as the temperature drops, solid gas hydrates may be formed and plugs the pipeline and other processing equipment (Carroll 2002). The water content of natural gases is thus, an important quantity to know, especially in connection with gas hydrate formation (Sloan 1990; Song et al. 1987). In the transmission of natural gas, another problem is further condensation of water. It can increase pressure drop in the line and often leads to corrosion problems. Thus, the water content of sour natural gases is an important parameter in the design of facilities for the natural gas production, transmission, and processing (Bahadori et al. 2009). The water content of a natural gas in saturated condition is mainly dependent on pressure and temperature conditions. The water content in a hydrocarbon gas phase decreases with pressure and temperature, Chapoy (2004). He asserts that, a system containing carbon dioxide and hydrogen sulphide contains more water at saturation than sweet natural gases, and it’s even more pronounced if the pressure is above 5MPa. Accurate knowledge of phase behaviour in water – sour gas system is essential to the design and operation of natural gas pipelines and production / processing facilities as much natural gas contain acid gases and water (Mohammadi et al. 2005). He had it that, since the acid/sour gases are normally saturated with water, it is necessary to estimate the equilibrium water contents of sour gases as a function of system temperature, pressure, and composition. This enables the calculation of amount of water condensed as a result of changes in the system conditions. There are many predictive methods developed for estimating water contents of gases. These methods can be divided into two categories (Mohammadi et al. 2005):  

Empirical or semi – empirical correlations and charts Thermodynamic models, which is based on equality of chemical potenetials.

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He also asserts that the main advantage of empirical or semi – empirical correlations and charts is the availability of data input and the simplicity of the calculations, while most of the available thermodynamic models could be installed on laptop computers. Using empirical or semi – empirical correlations and charts, Mohammadi et al. 2005 puts that, as long as the gas gravity of the mixture is closed to that of methane, and temperature is not too high, the effect of gas composition (in other word, gas gravity) can be ignored. He added that for lean and sweet natural gases containing over 70 mol percent methane and small amounts of heavy hydrocarbons, the effect of composition can be ignored and the water content can be assumed as a function of temperature and pressure. However, a detailed discussion on different methods with some conditions on which they provide high accuracy can be found in the some of these literatures: Mohammadi et al. (2005), Carroll (2002), Song et al. (1982), and others. In addition, accurate determination of water content of sour natural gases therefore requires a careful study of the existing literature information and available experimental data. In most cases, using additional experimental data is the best way to verify the model based predictions (Bahadori et al. 2009).

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5. Empirical Correlations and Calculation Methods In order to evaluate hydrate formation and prevention along a pipeline system, the various parameters described earlier in the introduction was computed analytically based on theoretical approach. Empirical correlations and charts were adopted; therefore this section will describe as well as discuss the various empirical correlations / models and methods employed in solving these problems.

5.1 Water Content of gas stream One of the major tasks of this work was to compute analytically the water content of a natural gas stream at the reservoir, wellhead, and the receiving terminal conditions. The composition of the natural gas is provided in the Appendix, Table A4. To solve this problem, it was pertinent to find a suitable but simple model based on existing scientific principles, or by adapting equations to experimental results for possible estimation. Literature such as Mohammadi et al. (2005) indicates that there are several methods of estimating water content of natural gas. In this work, Robinson et al.’s definition of equivalent hydrogen sulfide mol fraction was used in determining the equivalent hydrogen sulfide mol fraction and, it is given in the expression below: (1) where,

= equivalent mol fraction of hydrogen sulfide, = hydrogen mol fraction, and = carbon dioxide mol fraction. (Mohammadi et al. 2005)

He noted that this method is applicable for

< 0.4 (mol fraction), temperature in the

range of 283.15 to 450.15 K and pressure in the range of 2.07 to 69 MPa. The equivalent mol fraction of hydrogen sulfide was then used in the new correction factor developed by Mohammadi et al. (2005) to account for the effect of the acid gases. The correction factor expression is given as: [

( )

( )( )

( )]

(2)

where C1 to C3 = Mohammadi et al’s constant. 17

Fsour = correction factor for the sour content, T and P = system temperature and pressure respectively. To and Po = absolute temperature and pressure respectively. This is based on the fact that water content of an acid/sour gas is a function of temperature, pressure and acid gas equivalent H2S mol fraction. The constants used are provided in the Appendix, Table A1. However, the water content of the gas stream was then computed using the WichertWichert correlation which is given in equation (3) by the expression below: (3) where yw_sour and yw_sweet = water content of sour and sweet gas respectively. The water content of sweet gas was estimated using McKetta-Wehe chart provided in the Appendix, Figure A1, in that it is highly recommended, though it requires interpolation. However, the water vapour content that will be precipitated out of the gas stream was estimated as the difference between the water vapour content at the reservoir conditions and the water vapour content at the receiving terminal.

5.2 Temperature Profile The steady-state temperature profile of a subsea natural gas pipeline was analyzed based on the following assumptions:     

Steady-state flow and heat exchange (no problem variable is dependent on time); Physical properties for the mixture and the structure are independent on temperature and pressure; Only mixture temperature variation in the longitudinal direction is considered; Mixture is idealized homogeneous, that is, single phase flow; One dimensional heat transfer.

Considering Figure 8; as a representative of a pipeline transporting fluid from point A to point B. The pipeline was discretized or divided into equal segments and analyzing a short segment of length, ∆L (from T1 to T2), and then the gas temperature variation along the pipeline was determined by applying the principle of heat transfer. That is, equation (11) was applied to each segment of the pipeline. 18

Figure 8: Temperature variation along pipeline.

5.2.1 Necessary Equations and Variables To compute the steady state temperature profile of a subsea pipeline, the important variables and equations were surveyed. In steady-state conditions, the flowing fluid is cooled from the outside due to the cold seawater surrounding it. Assuming the cold seawater has a constant temperature, the following variables are used:  Mass flow rate (m) inside pipeline [kg/s];  Constant outside temperature, (Tsea)[K];  Pipeline inlet fluid temperature, (T1)[K];  Pipeline outlet fluid temperature, (T2)[K];  pipeline length, (L) [m];  pipeline internal diameter, (din) [m] Joule-Thomson cooling is not included in the derivation. (Gudmundsson 2011). The pipeline was envisioned as a long heat exchanger tube with cooling from the outside and the heat transferred is expressed as: (4) where q = heat transferred, U = overall heat transfer coefficient, A =heat transfer area, and ΔTLMTD = logarithmic mean temperature difference. The cooling of the flowing fluid inside a pipeline can be expressed by the equation: (

)

(5)

where Cp = heat capacity of the flowing fluid (fluid mixture). Based on the definition of the logarithmic mean temperature difference which is expressed as: (

) (

)

(6)

19

where Tu = Tsea, and setting in for constant outside temperature, this result in the following simplification: (7) The cooling from outside of the pipeline corresponds to the cooling of the fluid flowing inside the pipeline, thus resulting in the relationship: (

)

( )

(

)

(8)

where the heat transfer area is expressed by A = π*d*L, (Gudmundsson 2011). The relationship can be rewritten as: ( )

(9)

and ( )

(10)

Therefore, to determine the outlet temperature in each of the segment, the equation can be re-arranged thus: (

)

[

]

(11)

The temperature, T2 is the outlet temperature for each pipeline segment with an inlet (wellhead) temperature T1. Equation (11) was then used in computation of temperature variation along this pipeline.

5.2.1.1 Heat Capacity Estimation Heat capacity depends on temperature but is practically independent of pressure, Gudmundsson (2011). The heat capacity of a mixture of fluid (oil, gas and water well mixed) can be estimated from the relationship: (12) where x-values = the mass fractions of the oil, gas, and water phases respectively, CpM = heat capacity of the mixture. In this study, a homogeneous single phase (gas) flow was assumed, and the heat capacity correlation was reduced to: (13) where xg = mass fraction of the gas phase and Cpg = specific heat capacity of gas. Cp = heat capacity of gas 20

The specific heat capacity Cpg was estimated by interpolating through the heat capacity chart (Moshfeghian 2009), as a function of temperature and specific gravity and at constant pressure. The heat capacity chart is provided in the Appendix, Figure A3.

5.2.1.2 Mass Rate The mass rate of the system was computed using the expression below: (14)

where qg = gas flow rate and ρ = gas density. From the assumption that the physical properties of the mixture are independent upon temperature and pressure, the gas density was estimated from the correlation given below in equation (15). In other word, the density was determined at standard conditions. Recall that an ideal gas law is given by: and density: . Thus, combining the two relationships, density can also be expressed as: (15)

where Ps, = pressure, Ts = temperature, Zs = compressibililty at standard conditions. Mw = gas molecular weight, and R = gas constant.

5.3 Pressure Profile The total pressure drop in pipelines and wells consists of pressure drop due gravity (∆p g), acceleration (∆pa), and frictional forces (∆pf), Gudmundsson (2011). This can be expressed mathematically as: ∆pT = ∆pg + ∆pa + ∆pf

(16)

21

Figure 9: Steady-State flow in gas pipeline.

Assuming that there is no elevation (that is, the pipeline is horizontal), then the pressure drop is mainly due to friction losses between the pipe wall and the fluid. Then, total pressure drop of compressible fluids (gas) due to friction in horizontal pipe was surveyed from the expression given below, Gudmundsson (2011): (

)

( )

(17)

The natural logarithm term is quite small and can be ignored, Gudmundsson (2011). Simplifying for P2 yields: √

(18)

where f = friction factor, m = mass rate, z = gas compressibility factor, L = pipeline length, T = system temperature, d = pipe’s diameter, R = gas constant, M = gas molecular weight, and A = pipeline cross sectional area. The pressure at the end of each pipeline segment was then computed using equation (18) and the pressure drop was then computed as the difference between the inlet pressure (P 1) and outlet pressure (P2) which can be expressed as: ∆PT = P1 – P2

(19)

5.3.1 Necessary Parameters and Equations The pipeline throughput (flow rate) depends on the gas properties, pipe diameter and length, initial gas pressure and flowing temperature, and the pressure drop due to friction.

22

Considering flow through a horizontal pipe segment of length, L, in Figure 9, the upstream pressure P1 and a downstream pressure P2, (P1 –P2) represents the driving force that causes the flow and the longer the pipe length for a given pressure the larger the pressure drop. However, iteration was performed on the pipeline diameter to obtain a reasonable pipe diameter that will ensure flow with less pressure drop. Thus, subsequent sub-sections discuss these important dependent parameters and variables.

5.3.1.1 Reynolds Numbers Reynolds number is a dimensionless parameter used to characterize the type of flow such as laminar, turbulent, or critical flow in a pipe. It is a function of fluid properties (such as density, gas flow rate, and viscosity) and pipe internal diameter. It is expressed mathematically as: (20) where ρ = fluid density, v = fluid velocity in the pipe, d = pipeline internal diameter, μ = fluid viscosity. Laminar flow occurs in a pipeline when the Reynolds number is below a value of approximately 2000. Turbulent flow occurs when the Reynolds number is greater than 4000. For Reynolds numbers between 2000 and 4000, the flow is undefined and is referred to as critical flow (Menon 2005).

5.3.1.2 Density This is dependent upon the system pressure, gas compressibility and temperature. Recall that an ideal gas law is given by: And, density: . Therefore, density relationship can also be mathematically expressed as: (21) where p, T, and z = system pressure, temperature, and compressibility respectively, Mw = gas molecular weight, and 23

R = gas constant.

5.3.1.3 Velocity Considering a pipe segment; the velocity of the flowing gas changes with density and the pipe’s internal diameter. It is also a function of fluid rate (q) along the pipe which is given as: ; and, And, combining these equations and simplifying for velocity, gas velocity was then determined using the expression below: (22) where m = mass flow rate of the fluid, A = pipeline cross sectional area.

5.3.1.4 Viscosity The dynamic viscosity of a fluid is a unique function of fluid composition, pressure and temperature. As the gas flows in the pipeline, the viscosity changes with change in temperature and pressure. In this work, the Lee-Gonzales-Eakin’s (LGE) correlation was used, (Gudmundsson 2011 and Jeje et al. 2004), and it has the following form: (

)

(23)

where:

(

)

where k1 to k5, and x1 to x3 = constants. These constants are provided in the Appendix, Table A2.

24

5.3.1.6 Gas Compressibility Factor (Z) The compressibility factor is a measure of how close a real gas is to an ideal gas. The compressibility factor is a dimensionless number and it’s a function of the gas gravity, temperature, pressure, and the critical properties of the gas. For a natural gas mixture, reduced temperature and reduced pressure is used in determining gas compressibility, Gudmundsson (2011). There are several approaches to calculating the compressibility factor for a particular gas temperature (T) and pressure (P). Hall and Yarborough equation fitted to standing-Katz chart was used in this work (Whitson et al. 2000). This is based on the reduced pressure and reduced temperature and it is expressed as: (24) (

where:

(

) )

y = reduced-density parameter, (it is the product of a van der Waals co-volume and density), was obtained by solving the expression below: ( )

(

(

)

)

(

)

with ( )

( ( ) )( ) where Tpr and Ppr = pseudo reduced temperature and pressure respectively.

)

(

5.3.1.6 Friction factor There are various correlations for estimating friction factor of pipes. But in this work, Haaland’s friction factor correlation for pipes with rough walls was used as expressed in equation (25). It is dependent upon Reynolds number and the relative pipe roughness, Gudmundsson 2011. The relative pipe roughness is given as the ratio of pipe roughness to the diameter of the pipe. √

[( )

(

)

]

(25) 25

where n = 1 for liquids, and n = 3 for gases. Haaland’s equation is especially suited for gas pipelines if n=3, Sletfjerding et al. 2001.

5.4 MEG Estimation The formation of hydrates in gas pipeline systems can be addressed by using thermodynamic inhibitors which alter the fluid’s composition. Chemical inhibitor considered in this study is the mono ethylene glycol (MEG). This is based on the information obtained from the literature such as Estefen et al. (2005). Hammerschmidt’s correlation, the simplest correlation was used to estimate the amount of inhibitor required to lower hydrate formation temperature (Gudmundsson 2011). (

)

(26)

where K = Inhibitor’s constant, Mw = Inhibitor’s molecular weight, ∆T = hydrate depression temperature, and x = inhibitor’s mass concentration. The required inhibitor’s concentration (MEG) was obtained by solving equation (26) and it is expressed as: (

)

(27)

The inhibitor’s constant of MEG used in this analysis was 1222, and molecular weight of the MEG was 62.00 kg/kmol, (Gudmundsson 2010). The following assumptions were however made that:    

The gas is saturated at wellhead conditions, The water is pure (in other word, effect of salt is not considered), Flow is at steady state conditions, and that hydrates form at 20°C. A safety factor of 5oC was also included in this analysis.

The dew point depression is given as the difference between the hydrate formation temperature and the final terminal temperature. Hydrate formation temperature was determined using the pressure-temperature curve (GPA Handbook). This chart is provided in the Appendix, Figure A2. Water mass rate was determined as the product of gas mass rate and mol fraction of water condensed expressed as: 26

(28) Where mg = mass rate of gas and xw = mol fraction of water. However, the mass rate of hydrate inhibitor required was estimated as the product of mass rate of water and the mol fraction of the inhibitor. This is expressed as: mMEG = mwxMEG

(29)

where mw = mass rate of water and xMEG = mol fraction of inhibitor.

27

6. Results and Discussion The main objective of this work was to study flow assurance of a natural gas produced offshore and transmitted through a pipeline to shore. Analyzes done as described in the introduction, were based on the fact that hydrates formation are favoured by low temperature, high pressure and presence of water. A typical natural gas composition from Nigeria was used in this study. The natural gas composition obtained is provided in the Appendix, Table A4, with slight modification by this author to account for some compositions that were not present, just for purpose of this analysis. However, this section will present the results for the different analyzes that were considered in this work.

6.1 Water Content of Natural Gas at different Conditions In this work, empirical correlations and charts were used as described in the methods. Water content of natural gas stream containing acid/sour gas was estimated with the contribution of the acid/sour gases accounted for by the correction factor. It is obvious that acid gas correction factor increases as temperature and pressure decreases (that is, from the reservoir to the receiving terminal). The result also shows that the gas holds less water in the gas phase at these different conditions. This is summarized in Table 3 below: Table 4: Water Content of Gas at different conditions

Water Content mg/Sm3

Pressure bara

Temperature o C

Sour Gas Correction Factor

Reservoir

290.00

90.00

0.9785

3495

Wellhead

200.00

80.00

0.9855

3063

Terminal

113.34

17.59

0.9932

374

Conditions

The water vapour condensed out of the gas phase at the wellhead is 432.67 mg/Sm3 and at the receiving terminal at shore, it is 2689.04 mg/Sm3. However, the difference between the water content at reservoir condition and the water condensed at the receiving terminal, amounts to the quantity of water that needs to be removed or prevented from forming hydrates. The total value of condensed water at the receiving terminal is approximately 806 mg/Sm3 which is high enough to cause hydrates formation with the presence of other 28

favourable conditions. It is necessary to control the water content of gas to ensure safe operation of gas pipeline.

6.2 Temperature Profile From the given rate of gas (35∙106 Sm3/day), the arrival temperature of this system is approximately 18 oC. This indicates that in steady state thermal analysis, with constant mass rate, heat capacity, the overall heat transfer coefficient and the pipeline’s internal diameter (600 mm), the gas temperature along the pipeline tends towards the constant sea (ambient) temperature (10 oC). This is shown in Figure 11.

Steady state temperature profile 80.0

70.0

60.0

Temperature, T(oC)

50.0

40.0

30.0

20.0

10.0

0.0 0

20000

40000

60000

80000

100000

120000

Distance, L(m) Figure 10: Steady-State Temperature Profile

The result of this analyzes points out that the fluid is within hydrate forming region (temperature) when compared to the theoretical or necessary conditions (less than 21 oC) 29

that favours hydrate formation. The pipeline is exposed to the cooling sea current, thus the gas inside the pipeline is cooled down to temperatures that favour hydrate formation. In steady state operation, the production fluid temperature decreases as it flows along the pipeline due to heat transfer through pipe walls. This steady state temperature profile from the produced fluid can be used to identify the flow rates and insulation preference that can keep the system above the critical minimum temperature during production. Thermal analysis of a typical subsea production system, which predicts the temperature profile along the flowline, is one of the most important steps in the subsea layout design (Vianna et al. 2009). However, heat transfer analysis of the pipeline systems is of great importance for the prediction and prevention of hydrate formations. Accurate knowledge of the temperature field in the equipment combined with the knowledge of the critical temperature values for solid deposit formations must be adequately evaluated in order to ensure continued production at desired levels for profitability.

6.3 Pressure Profile The analysis of steady state pressure drop in a gas pipeline in this study was evaluated using a correlation published in Pressure drop in Gas Pipeline, TPG 4140 (Gudmundsson 2010). The initial wellhead pressure which is the pipeline’s inlet pressure was 200 bara and the arrival terminal pressure estimated is approximately 113 bara. This gives a total pressure drop (∆PT) of approximately 87 bara for a flow rate of 35∙106 Sm3/day, and a pipeline diameter of 600 mm. It was observed that the velocity of gas changes due to changes in gas compressibility which is a function of pressure, temperature and gas composition. However, from this result, it can be said that this flow is not out of hydrate forming region, based on theoretical conditions that high pressures favours hydrate formation in a gas pipeline (usually 100 bara and above). The steady-state pressure profile along the pipeline is presented in Figure 11.

30

Steady State Pressure Profile 200.0 180.0 160.0

Pressure, P (bara)

140.0 120.0 100.0 80.0 60.0 40.0 20.0 0.0 0

20000

40000

60000

80000

100000

120000

Distance, L (m) Figure 11: Steady-State Pressure Profile

6.4 Hydrate Inhibition Using MEG The formation of hydrates in gas pipeline systems can be addressed by using thermodynamic inhibitors which alter the fluid’s composition. In this study, MEG was considered and the Hammerschmidt’s correlation was used in estimating the required concentration of inhibitor to prevent hydrates from forming. From the result, the required amount of MEG estimated was 27.32 %, with an upstream (wellhead) rate of 9.24 kg/s (798.350 tonne/day). The estimated quantity of vapour condensed out of the gas phase at the terminal to be inhibited from forming hydrates was 806.23 mg/Sm3. The increased amount of produced water will require an increased amount of MEG to maintain the correct concentration to prevent hydrate formation.

31

7. Discussion of Project Work 7.1 Quality of Model The mathematical model presented showed a bit complex approach to estimating parameters such as water content of sweet gas, the heat capacity of gas, and hydrate depression temperature. They all require interpolations through a chart.

7.2 Quality of Input Data and Results The natural gas composition data from Nigeria was scarce. The quality of the gas compositions was not as obtainable at the reservoir (that is, some compositions like Hydrogen sulfide, Carbon dioxide, and Nitrogen were not included), thus, an adjustment was made and this can affect the results. However, economic analysis, extra quantity of inhibitor considered in this work that could be stored in the tank during production operation was not done, as well as transient analysis for this system was not also done.

7.3 Potential Improvements There are plans to improve on the quality of the input data and the results. These plans include: making of transient analysis of this flow along the pipeline analytically for both the temperature and pressure profiles, economic analysis of the inhibitor and estimation of the extra quantity of inhibitor in the storage tank. For the gas composition data, the quality would be improved by searching for another data that will contain the necessary compositions as obtainable at the reservoir. However, sensitivity analysis would be performed on some important parameters like price of inhibitors, pipeline’s internal diameter, etc. to observe their possible effects in managing or controlling hydrates formation.

32

8. Conclusion Produced natural gas stream from the reservoir is always saturated with water. One of the problems associated with the transmission of this fluid especially in offshore / subsea environments to shore through pipeline is the formation of hydrates. Thus, the important parameters and factors that favour hydrate formation must be understood if hydrates are to be controlled or managed. Water content estimation of a natural gas stream at the reservoir, wellhead and the receiving terminal conditions is one of the important parameters that must be understood if successful operations of pipeline transmission systems are to be ensured. The estimated amount of water vapour condensed was 803.23 mg/Sm3. In the thermal analyzes, the initial wellhead temperature was 80 oC and the arrival temperature is 17.59 oC giving rise to a total temperature drop of 62.41 oC. Thus, the gas flow is not out of hydrate forming region as the terminal arrival temperature was below 20 o

C.

The pressure profile analyzes also results in a total pressure drop of 86.66 bara, with the arrival pressure of 113.34 bara. The initial wellhead pressure was 200 bara, thus arrival pressure also reflects pressure above 100 bara, a condition which also favours hydrates formation. Based on the fact that this flow is not out of hydrate forming conditions, MEG was considered for the prevention of hydrate plug formation. The total amount of hydrate inhibitor (MEG) required to prevent hydrate formation was estimated to be 798.35 tonne/day. Consequently, it is important to identify first the potentials of hydrate formation in a pipeline system and then plan on the necessary prevention strategy for safe operations.

33

Nomenclature MEG CAPEX OPEX P1 P2 A f z R T1 T2 din Tf QMEG L μg Tr Pr ρg Tc Pc CO2 Mw m Cp H2S TLMTD U xg THIs KHIs

Fsour To Po yw_sour yw_sweet

= = = = = = = = = = = = = = = = = = = = = = = = = = = = = = =

Mono-Ethylene-Glycol Capital Expenditure Operational Expenditure Upstream or Inlet Pressure (bara) Downstream or outlet Pressure (bara) Cross sectional Area of pipeline (m2) Friction factor Gas compressibility factor Gas constant (J/kmol.K) Upstream or Inlet temperature ( oC) Downstream or outlet temperature (oC) Pipeline internal diameter (m) Gas flowing temperature (oC) MEG flow rate (tonne/day) Pipeline Length (m) Gas viscosity (cp) Reduced temperature Reduced pressure Gas density (kg/m3) Critical temperature (K) Critical pressure (MPa) Carbon dioxide Molecular weight (kg/kmol) Mass rate (kg/s) Heat capacity (J/kg.K) Hydrogen Sulfide Logarithmic mean temperature difference (K) Overall heat transfer coefficient (W/m2.K) Gas mass fraction (kg/kmol) Thermodynamic hydrate inhibitors Kinematics hydrate inhibitors

=

Equivalent hydrogen sulfide (mol)

= =

Mole fraction hydrogen sulfide (mol) Mole fraction carbon dioxide (mol)

= = = = =

Sour gas correction factor Absolute temperature (oC) Absolute pressure (bara) Sour gas water content (mg/Sm3) Sweet gas water content (mg/Sm3) 34

∆L BC q K

= = = =

Change in pipe’s length (m) Before Christ Heat transfer (W) Inhibitor’s constant

35

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Pickering, P.F., Edmonds, B., Moorwood, R.A.S., Szczepanski, R. and Watson, M.J. ‘‘Evaluating New Chemicals and Alternatives for Mitigating Hydrates in Oil and Gas Production’’, 2001. A Paper Presented at the IIR Conference, Aberdeen, Scotland, 2001. Robinson, D.B., and Ng, H.J. ‘’Hydrate Formation and Inhibition in Gas or Gas Condensate Streams’’, 1986. Journal of Canadian Pet. Technol. 1986, 26 (3), 26-30. Rojey, A., Durand, B., Jaffrey, C., Jullian, S. and Valais, M. ‘’Le gaz Naturel: Production Traitement Transport,’’ Publications de l’Institut Français du Pétrole, Edition Technip, 1994. Sanchez, C.B. ‘’Optimization Methods for Pipeline Transportation of Natural Gas’’, 2010. Department of Informatics University of Bergen, Norway, October 2010. www.ii.uib.no/~conrado/.../Papers/PhD-Thesis-Conrado-Borraz.pdf (18.11.2011) Sharareh, A. ‘’Prediction of Gas-Hydrate Formation Conditions in Production and Surface Facilities.’’ 2005. http://repository.tamu.edu/bitstream/handle/1969.1/4220/etd-tamu2005B-PETE-Ameripo.pdf? (accessed 12 December, 2011). Sletfjerding, E. and Gudmundsson, J.S. ‘’Friction Factor in High Pressure Natural Gas Pipelines from Roughness Measurements’’, 2001. Department of Petroleum Engineering and Applied Geophysics Norwegian University of Science and Technology, Norway. www.ipt.ntnu.no/~jsg/.../paper01b/Amsterdam2001FrictionPaper.pdf (accessed 20 December, 2011). Sloan, E.D., Koh, C.A., Sum, A.K., Ballard, A.L., Shoup, G.J., Creek, J.L., McMullen, N., and Palermo, T. ‘’Hydrates: State of the Art Inside and Outside’’, 2009. JPT, Dec. 2009. www.spe.org/jpt/print/archives/2009/12/19DAS.pdf (accessed 12 December, 2011). Sloan, E.D. Jr., ‘’Fundamental Principles and Applications of Natural Gas Hydrates’’, 2003. Center for Hydrate Research, Colorado School of Mines, Golden, Colorado, USA. Nature Publishing Group. Vol. 426, 20 November, 2003. Sloan, E. D. ‘’Clathrate Hydrates of Natural Gases’’, 1990. Chem. Industries, vol. 39. Sloan, E.D. ‘’Clathrate Hydrates of Natural Gases,’’ 1998. Marcel Dekker Inc., (Second Edition), New York. Song, K.Y., and Kobayashi, R. ‘’Measurement and Interpretation of the Water Content of a Methane-Propane Mixture in the Gaseous State in Equilibrium with Hydrate’’, 1982. Ind. Eng. Chem. Fundamentals, Vol. 21, p391-395. http://pubs.acs.org/doi/abs/10.1021/i100008a013 (accessed 20 December, 2011). 39

Song, K.Y., Kobayashi, R. ‘’ Water Content of Carbon Dioxide in Equilibrium with Liquid Water and/or Hydrates’’, 1987. SPE Formation Evaluation Journal, SPE - 15905-PA. p500-508. Vianna, F.L.V., Orlande, H.R.B. and Dulikravich, G.S. ‘’Estimation of the Temperature Field in Pipelines by Using the Kalman Filter’’, 2009. Paper presented at 2 nd International Congress of Serbian Society of Mechanics (IConSSM). Serbia, 1-5 June 2009. D-13:1-10. Whitson, C.H. and Brule, M.R. ‘’Phase Behaviour’’, 2000. SPE Monograph Series, Henry L. Doherty Memorial Fund of AIME, SPE Richardson, Texas. Vol.20. p18-29. Zarinabadi, S. and Samimi, A. ‘’Problems of Hydrate Formation in Oil and Gas Pipes Deals’’, 2011. Australian Journal of Basic and Applied Sciences, 5(12): 741-745. ISSN 1991-8178.

40

Appendix A Table A1: Sour gas correction factor constants, (Mohammadi et al. 2005)

Mohammadi et al. Constants C1

0.03185

C2 C3

0.01538 -0.02772

Table A2: Constants in LGE equation (Jeje et al. 2004)

Lee, Gonzales & Eakin (LGE) Method LGE Constants k1 9.379 k2 0.01607 k3 1.5 k4 209.2 k5 19.26 x1 3.448 x2 986.4 x3 0.01009 y1 2.447 y2 0.2224

Table A3: Natural Gas Reservoir, Production & Pipeline Parameters

Reservoir Pressure

PR

290

bara

Wellhead Pressure

Pwh

200

bara

Reservoir Temperature

TR

90

o

Wellhead Temperature

Twh

80

o

Seawater temperature

Tsea

10

o

Wellhead (template) Depth

Dwh

150

m

Total Natural Gas Rate

q

3.50E+07

Sm3/day

Pipeline Internal Diameter ID

din

600

mm

Pipeline Length Pipeline Overall Heat Transfer Coefficient

L U

120 10

km W/m2.k

Pipeline Roughness

Ԑ

35.10

microns

C C C

41

Figure A1: Water contents of natural gases, Mcketta and Wehe Chart (GPA Handbook).

42

Figure A2: Pressure-temperature Curves for Predicting Hydrate Formation Temperature (GPA Handbook).

43

Figure A3: Natural Gas Heat Capacity of 0.60 and 0.65 Specific Gravity (Moshfeghian, 2008)

44

Table A4: Natural Gas Stream Composition from Nigeria, with slight modification Source: Development of petrochemicals from natural gas (methane), Maina, N.S., 2005 (Dept. of Chemical Engineering, Ahmadu Bello University, Nigeria) (Original)

(Modified)

Component Symbol

Mol Percent

Mol fraction

Component Symbol

Mol %

Mol fraction, zi

Methane

C1

91.25

0.9125

Methane

C1

90.01

0.9001

Ethane

C2

3.61

0.0361

Ethane

C2

5.35

0.0535

Propane

C3

1.37

0.0137

Propane

C3

2.46

0.0246

i-Butane

i-C4

0.31

0.0031

i-Butane

i-C4

0.31

0.0031

n-Butane

n-C4

0.44

0.0044

n-Butane

n-C4

0.38

0.0038

i-Pentane

i-C5

0.16

0.0016

i-Pentane

i-C5

0.21

0.0021

n-Pentane

n-C5

0.17

0.0017

n-Pentane

n-C5

0.2

0.002

Hexane

C6

0.27

0.0027

C6

0.05

0.0005

Heptane+

C7+

2.42

0.0242

Hexane Heptane plus

C7+

0.57

0.0057

CO2

0

0

Nitrogen

N2

0.04

0.0004

H2S

0

0

CO2

0.14

0.0014

N2

0

0

H2S

0.28

0.0028

100

1

100

1

Carbon dioxide Hydrogen Sulphide Nitrogen Total

Carbon dioxide Hydrogen Sulphide Total

45

Table A5: Temperature Profile Data

Segment Pipeline Number Segment dL # m 1 0 2 100 3 200 4 300 5 400 6 500 7 600 8 700 9 800 10 900 11 1000 12 1100 13 1200 14 1300 15 1400 16 1500 17 1600 18 1700 19 1800 20 1900 21 2000 43 4200 1190 118900 1191 119000 1192 119100 1193 119200 1194 119300 1195 119400 1196 119500 1197 119600 1198 119700 1199 119800 1200 119900 1201 120000

Pipeline Temperature Ti o

C 80.000 79.871 79.741 79.612 79.484 79.355 79.227 79.099 78.971 78.843 78.716 78.589 78.462 78.335 78.209 78.083 77.957 77.831 77.706 77.581 77.456 74.763 17.747 17.733 17.718 17.704 17.690 17.676 17.661 17.647 17.633 17.619 17.605 17.591

46

Table A6: Pressure Profile Data

Pressure Profile Determination Segment Pipeline Pipeline Compressibi Serial Segment Temperature lity factor Density Velocity Number ρg dL Ti U Z o # C m kg/m3 m/s 1 0 80.000 0.8835 143.473 7.8485 2 100 79.871 0.8833 143.559 7.8438 3 200 79.741 0.8831 143.591 7.8420 4 300 79.612 0.8829 143.624 7.8402 5 400 79.484 0.8826 143.657 7.8384 6 500 79.355 0.8824 143.690 7.8367 7 600 79.227 0.8822 143.722 7.8349 8 700 79.099 0.8819 143.755 7.8331 9 800 78.971 0.8817 143.787 7.8313 10 900 78.843 0.8815 143.820 7.8296 11 1000 78.716 0.8812 143.852 7.8278 12 1100 78.589 0.8810 143.885 7.8261 13 1200 78.462 0.8808 143.917 7.8243 14 1300 78.335 0.8806 143.949 7.8225 15 1400 78.209 0.8803 143.981 7.8208 1193 1194 1195 1196 1197 1198 1199 1200 1201

119200 119300 119400 119500 119600 119700 119800 119900 120000

17.704 17.690 17.676 17.661 17.647 17.633 17.619 17.605 17.591

0.7597 0.7598 0.7599 0.7600 0.7600 0.7601 0.7602 0.7603 0.7604

115.775 115.662 115.549 115.435 115.321 115.207 115.093 114.978 114.862

9.7262 9.7357 9.7452 9.7548 9.7644 9.7741 9.7838 9.7936 9.8034

Constants

X

Y

K

5.188 5.188 5.189 5.189 5.190 5.190 5.191 5.191 5.192 5.193 5.193 5.194 5.194 5.195 5.195

1.293 1.293 1.293 1.293 1.293 1.293 1.293 1.292 1.292 1.292 1.292 1.292 1.292 1.292 1.292

128.905 128.859 128.813 128.767 128.721 128.676 128.630 128.585 128.539 128.494 128.449 128.404 128.359 128.314 128.269

5.520 5.520 5.520 5.520 5.520 5.520 5.520 5.521 5.521

1.219 1.219 1.219 1.219 1.219 1.219 1.219 1.219 1.219

106.249 106.244 106.239 106.233 106.228 106.223 106.217 106.212 106.207

Haaland's Total Outlet Reynolds Friction Pressure Pressure Drop Viscosity Number Factor P2 dPT μ Re fH mPa.s bara bara 0.0196 34399147 0.0108 200.00 0.00 0.0196 34395012 0.0108 199.92 0.08 0.0196 34397808 0.0108 199.84 0.16 0.0196 34400597 0.0108 199.76 0.24 0.0196 34403379 0.0108 199.68 0.32 0.0196 34406153 0.0108 199.60 0.40 0.0196 34408921 0.0108 199.52 0.48 0.0196 34411681 0.0108 199.44 0.56 0.0196 34414434 0.0108 199.36 0.64 0.0196 34417180 0.0108 199.28 0.72 0.0196 34419919 0.0108 199.20 0.80 0.0196 34422650 0.0108 199.13 0.87 0.0196 34425375 0.0108 199.05 0.95 0.0196 34428094 0.0108 198.97 1.03 0.0196 34430805 0.0108 198.89 1.11 0.0158 0.0158 0.0158 0.0158 0.0158 0.0158 0.0158 0.0158 0.0158

42701098 42722431 42743828 42765288 42786813 42808401 42830054 42851772 42873556

0.0108 0.0108 0.0108 0.0108 0.0108 0.0108 0.0108 0.0108 0.0108

114.19 114.08 113.98 113.87 113.77 113.66 113.55 113.45 113.34

47

85.81 85.92 86.02 86.13 86.23 86.34 86.45 86.55 86.66

B. Calculation Procedure I present here the calculation procedures of the various inputs used in this work for the evaluation of hydrates formation and prevention, but the equations with the important parameters are discussed in the empirical correlations and calculation methods section. The natural gas composition data was first obtained and other necessary data provided in Appendix A, and then the formulas to be used was decided for the calculations of the needed values. For water vapour estimation at different conditions, the equivalent hydrogen sulfide was first determined and it was used for the calculation of the sour gas correction factor. Sweet gas water content was determined using Mcketta-Wehe chart, and the water content of the gas was then estimated as the product of the sweet gas water content and the sour gas correction factor. For temperature drop, I needed to calculate the specific gravity of the gas using the molecular weight and the pseudocritical properties of the gas compositions. I further on to calculate the mass rate of the gas at standard conditions and the temperature profile along the pipeline was then calculated. I continued on the pressure drop along the pipeline. The gas compressibility was calculated using reduced temperature and pressure, and it is highly dependent on pressure and temperature of the system. I further calculate the density, velocity, viscosity, Reynolds number, friction factor, and then outlet pressure for each pipe’s segments. And, finally the total pressure drop along the pipeline. Finally, for the prevention of hydrate formation using MEG, I first determined hydrate depression point. From the percentage of water condensed, water mass rate was determined, and with the estimated amount of MEG, the required quanity of inhibitor (MEG) at the wellhead to prevent hydrate formation and blockage of pipeline during transmission was estimated.

48