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Hydrates

ما هي الهيدرات Hydrates وما هي طرق معالجتها؟


الهيدرات Hydrates  وهي أشبه بالثلج الوسخ ، حيث تتكون من مزيج من الماء مع بعض جزيئات الهيدروكاربونات الخفيفة (غالباً ما تكون الميثان والأيثان وثاني أوكسيد الكاربون) وهي بلورات غير محكمة وتسمى هذه المادة الكيمياوية (cathrates) .

ويجب توافر ثلاثة شروط لتكون الهيدرات:

1. درجة الحرارة والضغط المناسبين ، حيث أنه يتكون في درجات الحرارة الواطئة + الضغوط العالية. حيث إن أنخفاض درجة حرارة الغاز الى أقل من درجة الندى Dew Point  فأن هذا يؤدي الى تكون (الماء الحر). أن درجة الحرارة المُثلى لتكوين الهيدرات تعتمد على مكونات الغاز.

2. يجب توافر 3 مواد أساسية لتكوين الهيدرات وهي (الميثان – الأيثان – ثاني أوكسيد الكاربون).

3. توافر كمية كافية من الماء.

بالأضافة الى أن وجود بعض الظواهر يزيد من أحتمالات تكونها وهي:

1. أضطراب الجريان : ويكون ذلك لسببين:

   أ. السرعة العالية  ، مما يجعل الصمامات الخانقة Choke Valves المكان الأمثل لتكون الهيدرات  وذلك بسبب الفرق في درجة الحرارة خلال الصمام Temp. Drop  بسبب قانون (جول – ثومبسون) ، بالأضافة الى السرعة العالية التي يسببها تضيق الصمام.

   ب. المزج أو الخلط Agitation  : حيث أن المزج خلال الأوعية أو المبادلات الحرارية يعزّز تكون الهيدرات.
يتعزز تكون الهيدرات في الأماكن التي يحدث فيها تكون للطور الصلب أو الطور السائل ، ويحصل هذا الأمر في الأنابيب مثل نقاط اللحام أو بعض الملحقات مثل ( الأنحناءات – حرف T في الأنابيب – الصمامات ) أو وجود الأوساخ ، الصدأ .

  1. وجود الماء الحر Free Water :  أن وجود الماء الحر يعزّز تكون الهيدرات كما أن الحد الفاصل بين الماء والغاز يكون أمراً مساعداً الى حد كبير في تكونها.

أن من الأمور المهمة الأخرى هو وجود المواد الصلبة حيث أن  الهيدرات تتنقل في الأنبوب بواسطة الطور السائل وتميل الى التجمع في نفس الأماكن التي يتجمع فيها السائل ، وتكمن المشكلة في الأماكن التي تتجمع فيها الهيدرات ، وخاصة في الأنابيب التي يحصل فيها جريان متعدد الأطوار Multiphase flow  حيث أن تجمع الهيدرات يؤدي الى حدوث أنسدادات في الأنبوب.

أن أستعمال القشط  Pigging يعتبر  طريقة مناسبة لإزالة الهيدرات من الأنابيب ، ويمكن إجراء عملية القشط من خلال أدخال أداة تسمى القاشطة Pig الى الأنبوب  ، وتتضمن القاشطات الحديثة عدة تقنيات ولكن أهمها بالتأكيد هو تنظيف الأنبوب ، ويجب أن تكون بنفس قطر الأنبوب ويتم دفعها وتسييرها بضغط الغاز  وتقوم بإزالة كل المواد الصلبة منه مثل (الهيدرات – الشمع – الأوساخ .. ألخ) بالأضافة الى دفع السوائل من المناطق التي تتجمع فيها. 

 ويمكن تصنيف الهيدرات تبعاً لترتيب جزيئات الماء في البلورة وبالتالي تركيب البلورة. وهذا المصطلح يشير الى المركبات التي تكون بهيئة مستقرة لكنها لاتنتج عن أتحاد كيمياوي صحيح لكل الجزيئات.  وتتكون الهيدرات عادةً  عند تبريد الغاز الى أقل من درجة تكون الهيدرات. وفي الضغوط العالية تتكون هذه الهيدرات في درجات حرارة أعلى من 32 ̊ F .

وهناك 3 أنواع من الهيدرات في الصناعة النفطية: النوع الأول Type I، والنوع الثاني Type II ، والنوع الثالث Type H والجدول التالي يبين الفرق بين هذه الأنواع:

Type H Type II Type I  
34 136 46 Water Molecules per Unit Cell
              Cages per Unit Cell
3 16 6 Small
2 Medium
1 8 2 Large
0.15 0.15 0.1481 All Cages Filled
Mole fraction hydrate former
0.0556 0.1154 Only Large Cages Filled
Mole fraction hydrate former
               Cavity Diameter
7.8 7.8 7.9 Small
8.1 medium
11.2 9.5 8.6 Large
  5.178 x 10 -27 1.728 x 10 -27 Volume of Unit Cell (m3)
see text N2,C3H8
i-C4H10
CH4,C2H6
H2S, CO2
Typical Formers
 

أن تكوّن الهيدرات أمر غير مرغوب فيه لأن هذه البلورات قد تسبب حدوث أنسداد في أنابيب الجريان flowlines ، الصمامات وبالذات الصمامات الخانقة chokes ، بالإضافة الى صمامات السيطرة مما يقلل سعة الأنابيب أو يسبب تضررها وذلك بسبب فرق الضغط العالي والـ orifices الصغيرة حيث أن هذا الفرق يؤدي الى تقليل درجة الحرارة مما يجعلها عرضة لتكون الهيدرات والانسداد. وعادةً ما يؤدي هذا الأمر الى حدوث الأنجماد FREEZING مما يقلل الى تقليل التدفق خلالها.

ومع تقليل الضغط ، تزيد درجة الحرارة التي تتكون فيها الهيدرات ، وفي حالة عدم وجود ماء حر فهذا يعني عدم تكون الهيدرات ، كما توجد بعض العوامل الثانوية التي تساعد على تكون الهيدرات مثل : سرع الغاز العالية ، أي نوع من المزج. 

 

أن أكثر الطرق شيوعاً لمنع تكون الهيدرات هي التسخين وذلك لضمان عدم هبوط درجة الحرارة الى الحد الذي تتكون فيه الهيدرات ، أو تجفيف الغاز وذلك لعدم فسح المجال لبخار الماء بالتكاثف الى الماء الحر.

أنخفاض درجة الحرارة بسبب تمدد الغاز

أن الخنق throttling أو تمدد الغاز من ضغط عال الى ضغط واطئ أمر مطلوب للسيطرة على تدفق الغاز ، والخنق يحصل بسبب الصمامات الخانقة أو صمامات السيطرة ، ان فرق الضغط يؤدي يسبب أنخفاض درجة الحرارة مما يؤدي الى تكون الهيدرات في هذه الصمامات. 

 

أن أهم أنواع الإضافات الكيمياوية لمنع تكون الهيدرات هو الميثانول , وهو رخيص نسبياً ، يذوب في الهيدروكاربونات ، وفي حالة وجود مكثفات Condensate يتوجب إضافة المزيد من الميثانول لأن قسم منه سيذوب في المكثفات ، كما أن قسماً آخر منه سيتبخر الى الحالة الغازية. كما أن (الأثيلين كلايكول EG) هو الآخر شائع الأستخدام في هذه الحالة ، لأنه أقل ذوبانية في الهيدروكاربونات وأقل تبخراً من الميثانول. 

كيفية تجنب تكوّن الهيدرات :

يجب أزالة أحد عوامل تكون الهيدرات المذكورة أعلاه ، وبشكل عام لا يمكن إزالة أحد العوامل المكوّنة للهيدرات (الميثان والأيثان وثاني أوكسيد الكاربون) حيث أنها من المواد المرغوبة في الغاز الطبيعي لذلك يجب علينا محاولة إزالة العاملين الآخرين.

معالجة الهيدرات:

   يمكن أستخدام وحدات Low Temperature Exchange LTX والتي تؤدي الى ذوبان الهيدرات بسبب الحرارة العالية لأنها (الهيدرات) تفضل درجات الحرارة الواطئة)

 

     ولهذه  العملية فوائد أخرى مثل تثبيت المكثفات وبعض المركبات الهيدروكاربونية الوسطية أكثر مما يحصل في عمليات العزل الأعتيادية.

  وعادة ً ما تستعمل المسخنات غير المباشرة indirect Fired Heaters (وهي الأكثر شيوعاً) التي تقوم بتسخين وسط ثالث يقوم بدوره بتسخين خط جريان الغاز قبل و/أو بعد الصمام الخانق لأبقاء الغاز فوق هذه درجة تكون الهيدرات. كما توجد العديد من المعدات الأخرى المبادل الحراري نوع shell & Tube أو المسخنات الكهربائية المغمورة ، المسخنات .. ألخ.

 

  يمكن الحفاظ على حرارة الأنبوب من خلال أستعمال السلك الحراري الكهربائي heat Trace الذي يغلف الأنبوب ويتم بواسطته تسخينه مما يحافظ على درجة حرارة الموائع الموجودة فيه ويمنع تكون الهيدرات بسبب الحفاظ على درجة الحرارة فوق درجة تكون الهيدرات ، ويفضّل استخدامه في الصمامات لأنها نقاط تضيق كما ذكرنا.

يمكن أستخدام تغليف الأنابيب Pipe Insulation كطريقة أخرى للحيلولة دون أنخفاض درجة حرارة الموائع وتكون الهيدرات.

كما يمكن أستخدام بعض المواد السائلة لمعالجة الهيدرات أو تقليل تأثيرها ، وهذه المواد تؤدي الى تقليل درجة الأنجماد أو تحريك توازن الهيدرات مقابل قيم الحرارة  المنخفضة وهذه المواد هي:

 – أثيل الكحول.

 – الميثانول.

 – داي أثيلين كلايكول DEG.

 

علماً ان الميثانول يسبب بعض المشاكل مثل : تركّزه في الغاز السائل LPG – اذابته للمواد مانعة التآكل Corrosion Inhibitors التي تستعمل في الانابيب والمنظومات. ويتراوح معدل حقن الميثانول من 0.15 – 1.5 م3/يوم  .  بالأضافة الى العديد من المواد الكيمياوية لوقف تآكل المعدات ، ولكنها في الغالب لتقليل تأثير هذه المشكلة.

Natural Gas Dehydration Part.1

Definition of Natural Gas Dehydration

 the removal of water from natural gas by lowering the dew point temperature of the natural gas

   Objective:

To prepare natural gas for sale, its undesirable components (water, H2S and CO2) must be removed. Most natural gas contains substantial amounts of water vapor
due to the presence of connate water in the reservoir rock. At reservoir pressure and temperature, gas is saturated with water vapor.
Removal of this water is necessary for sales specifications or cryogenic gas processing. Primary concerns in surface facilities are determining the:
– Water content of the gas.
– Conditions under which hydrates will form.
Liquid water can form hydrates, which are ice-like solids, that can plug flow or decrease throughput. Predicting the operating temperatures and pressures at which
hydrate form and methods of hydrate prevention.

Water vapor is the most common undesirable impurity in gas streams. Usually, water vapor and hydrate formation, i.e. solid phase that may precipitate from the gas when it is compressed or cooled. Liquid water accelerates corrosion and ice (or solid hydrates) can plug valves, fittings, and even gas lines. To prevent such difficulties, essentially gas stream, which is to be transported in transmission lines, must be dehydrated as per pipeline specifications.
The processing of natural gas to the pipeline specifications usually involves four main processes :
Oil and condensate removal
Water removal
Separation of natural gas liquids
Sulfur and carbon dioxide removal
Most of the liquid free water associated with extracted natural gas is removed by simple separation methods at or near the wellhead. However, the removal of the water vapor
requires more complex treatment, which usually involves one of the two process, either absorption or adsorption.
In absorption, dehydrating agent (e.g. glycols) is employed to remove water vapors and in adsorption, solid desiccants like alumina, silica gel, and molecular sieves can be used.
The absorption process has gain wide acceptance because of proven technology and simplicity in design and operation.

  Dew Point:

   The dew point is the temperature and pressure at which the first drop of water vapor condenses into a liquid. It is used as a means of measuring the water vapor content of
natural gas. As water vapor is removed from the gas stream, the dew point decreases. Keeping the gas stream above the dew point will prevent hydrates from forming and
prevent corrosion from occurring.
Dew point depression is the difference between the original dew point and the dew point achieved after some of the water vapor is removed. It is used to describe the amount
of water needed to be removed from the natural gas to establish a specific water vapor content

  PRESENCE OF WATER IN NATURAL GAS :
Natural gas contains water in 2 forms :
–  In liquid form (free water) .
– In vapor form (dissolved)
Water present :
1. At source from reservoir (associated water with gas)
2. As a result of sweetening in aqueous solution.
It is necessary to reduce and control the water content of gas to ensure safe processing and transmission.

 WATER CONTENT IN NATURAL GAS
Water content is stated in a number of ways :
1. Mass of water/unit volume lb/MMscf.
2. Dew point Temperature.
3. Concentration, part per million by volume ppmv.
4. Concentration, part per million by mass ppmw.

   Why Dehydrate?

   Dehydration refers to removing water vapor from a gas to lower the stream’s dew point. If water vapor is allowed to remain in the natural gas, it will:
– Reduce the efficiency and capacity of a pipeline
– Cause corrosion that will eat holes in the pipe or vessels through which the gas passes Form hydrates or ice blocks in pipes, valves, or vessels
– Dehydration is required to meet gas sales contracts (dependent upon ambient temperatures).

Water Content of Gas:

   Liquid water is removed by gas-liquid and liquid-liquid separation. The capacity of a gas stream to hold water vapor is: A function of the gas composition Affected by the pressure and temperature of the gas Reduced as the gas stream is compressed or cooled When a gas has absorbed the limit of its water holding capacity for a specific pressure and temperature, it is said to be saturated or at its dew point.
Any additional water added at the saturation point will not vaporize, but will fall out as free liquid. If the pressure is increased and/or the temperature decreased, the capacity of the gas to hold water will decrease, and some of the water vapor will condense and drop out.
Methods of determining the water content of gas include:
– Partial pressure and partial fugacity relationships
– Empirical plots of water content versus P and T Corrections to the empirical plots above for the presence of contaminants such as hydrogen sulfide, carbon dioxide and
nitrogen and Pressure Volume Temperature (PVT) equations of state.

   GAS HYDRATES:

    What Are Gas Hydrates?
Gas hydrates are complex lattice structures composed of water molecules in a crystalline structure: Resembles dirty ice but has voids into which gas
molecules will fit Most common compounds.

    – Water, methane, and propane
– Water, methane, and ethane
The physical appearance resembles a wet, slushy snow until they are trapped in a restriction and exposed to differential pressure, at which time they become very solid structures, similar to compacting snow into a snow ball.

Why Is Hydrate Control Necessary?
Gas hydrates accumulate at restrictions in flowlines, chokes, valves, and instrumentation and accumulates into the liquid collection section of vessels. Gas hydrates plug and reduce line capacity, cause physical damage to chokes and instrumentation, and cause separation problems.

What Conditions Are Necessary to Promote Hydrate Formation?
Correct pressure and temperature and “free water” should be present, so that the gas is at or below its water dew point. If “free water” is not present, hydrates cannot form.

How Do We Prevent or Control Hydrates?
1. Add heat.
2. Lower hydrate formation temperature with chemical
3. inhibition Dehydrate gas so water vapor will not condense into “free water”.
4. Design process to melt hydrates.

 Why Using Glycols?
Glycols are extremely stable to thermal and chemical decomposition, readily available at moderate cost, useful for continuous operation and are easy to regenerate. These properties make glycols as obvious choice as dehydrating agents.
In the liquid state, water molecules are highly associated because of hydrogen bonding. The hydroxyl and ether groups in glycols form similar associations with water molecules. This liquid –phase hydrogen bonding with glycols provides higher affinity for absorption of water in glycol. Four glycols have been successfully used to dry natural gas: ethylene glycol (EG), Diethylene glycol (DEG), Triethylene glycol (TEG) and Tetraethylene glycol (TREG).
TEG has gained universal acceptance as the most cost effective choice because:
– TEG is more easily regenerated to a concentration of 98-99.95% in an atmospheric stripper because of its high boiling point and decomposition temperature.
– Vaporization temperature losses are lower than EG or DEG
– Capital and operating cost are lower
Diethylene glycol is preferred for applications below about 10oC because of the high viscosity of TEG in this temperature range.

for more details, see Natural Gas Dehydration Part.2

 References:
1. Gas Dehydration Field Manual, Maurice Stewart & Ken Arnold
2. Gas Dehydration by TEG and Hydrate Inhibition Systems, Arthur William
3. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

Natural Gas Hydrates

what are Hydrates

  1. Introduction to Hydrate

Natural gas hydrates are ice-like materials formed under low temperature and high pressure conditions. Natural gas hydrates consist of water molecules interconnected through hydrogen bonds which create an open structural lattice that has the ability to encage smaller hydrocarbons from natural gas or liquid hydrocarbons as guest molecules.

Interest in natural gas hydrates as a potential energy resource has grown significantly in recent years as awareness of the volumes of recoverable gas becomes more focused. The size of this resource has significant implications for worldwide energy supplies should it become technically and economically viable to produce. Although great efforts are being made, there are several unresolved challenges related to all parts in the process towards full scale hydrate reservoir exploitation. Some important issues are: 1) Localize, characterize, and evaluate resources, 2) technology for safe and economic production 3) safety and seafloor stability issues related to drilling and production. Thisarticle gives a brief introduction to natural gas hydrate and its physical properties. Some important characteristics of hydrate accumulations in nature are also discussed.

read also What is Natural Gas

Experimental results presented in this chapter emphasis recent work performed by the authors and others where we investigate the possibilities for producing natural gas from gas hydrate by CO2 replacement. By exposing the hydrate structure to a thermodynamically preferred hydrate former, CO2, it is shown that a spontaneous conversion from methane hydrate to CO2 hydrate occurred. Several experiments have shown this conversion in which the large cavities of hydrates prefer occupation by CO2.

read also Hydrate and Hydrate Prevention

  1. Structures and Properties

There are three known structures of gas hydrates: Structure I (sI), structure II (sII) and structure H (sH). These are distinguished by the size of the cavities and the ratio between large and small cavities. SI and sII contain both a smaller and a larger type of cavity, but the large type cavity of sII is slightly larger than the sI one. The maximum size of guest molecules in sII is butane. SH forms with three types of cavities, two relatively small ones and one quite large.

hydrate
hydrate

The symmetry of the cavities leaves an almost spherical accessible volume for the guest molecules. The size and shape of the guest molecule determines which structure is formed due to volumetric packing considerations. Additional characteristics are guest dipole and/or quadropole moments, such as for instance for H2S and CO2. The average partial charges related to these moments may either increase the stability of the hydrate (H2S) or be a decreasing factor in thermodynamic stability (CO2). SII forms with for instance propane and iso-butane and sH with significantly larger molecules, as for instance cyclo-hexane, neo-hexane. Both methane and carbon dioxide form sI hydrate. SI hydrates forms with guest molecules less than 6 Å in diameter. The cages and the number of each cage per unit cell are shown in Figure 1. SI cages are shown at the top of the figure. The unit cell of sI hydrate contains 46 water molecules and consists of 2 small and six large cages.

The unit cell is the smallest symmetric unit of sI. The two smaller cavities are built by 12 pentagonal faces (512) and the larger of 12 pentagonal faces and two hexagon faces (51262). The growth of hydrate adds unit cells to a crystal.

Classification of Hydrate Deposits

hydrate classes

Boswell and Collett, 2006, proposed a resource pyramid to display the relative size and feasibility for production of the different categories of gas hydrate occurrences in nature. The top resources of the gas hydrates resource pyramid are the ones closest to potential commercialization. According to Boswell and Collett, these are occurrences that exist at high saturations within quality reservoirs rocks under existing Arctic infrastructure.

This superior resource type is estimated by US geological survey (USGS) to be in the range of 33 trillion cubic feet of gas-in-place under Alaska’s North Slope. Prospects by British Petroleum and the US DOE anticipate that 12 trillion cubic feet of this resource is recoverable. Even more high-quality reservoirs are found nearby, but some distance away from existing infrastructure (level 2 from top of pyramid). The current USGS estimate for total North Slope resources is approximately 590 Tcf gas-in-places. The third least

challenging group of resources is in high-quality sandstone reservoirs in marine environments, as those found in the Gulf of Mexico, in the vicinity of existing infrastructure.

There is a huge variation in naturally occurring hydrate reservoirs, both in terms of thermodynamic conditions, hosting geological structures and trapping configurations (sealing characteristics and sealing geometry). Hydrates in unconsolidated sand are considered as the main target for production. For the sake of convenience, these types of hydrate occurrences have been further divided into four main classes,

Class 1 deposits are characterized with a hydrate layer above a zone with free gas and water. The hydrate layer is composed with either hydrate and water

(Class 1W) or gas and hydrate (Class 1G). For both, the hydrate stability zone ends at the bottom of the hydrate interval. Class 2 deposits exist where the hydrate bearing layer, overlies a mobile water zone. Class 3 accumulations are characterized by a single zone of hydrate and the absence of an underlying zone of mobile fluids. The fourth class of hydrate deposits is widespread, low saturation accumulations that are not bounded by confining strata that may appear as nodules over large areas. The latter class is generally not regarded as a target for exploitation.

Proposed Production Schemes

Hydrate

The three main methods for hydrate dissociation discussed in the literature are (1) depressurization, where the hydrate pressure is lowered below the hydration pressure PH at the prevailing temperature; (2) thermal stimulation, where the temperature is raised above the hydration temperature TH at the prevailing pressure; and (3) through the use of inhibitors such as salts and alcohols, which causes a shift in the PH-TH equilibrium due to competition with the hydrate for guest and host molecules. The result of hydrate dissociation is production of water and gas and reduction in the saturation of the solid hydrate phase.

Environmental Aspects of Gas Hydrates

  1. Climate change

The natural gas produced from hydrates will generate CO2 upon combustion, but much less than conventional fuel as oil and coal per energy unit generated. The global awareness of climate change will most likely make it more attractive in relation to oil and coal if fossil fuels, as anticipated, continue to be a major fuel for world economies the next several decades. However, increased global temperatures have the potential of bringing both permafrost hydrates and subsea hydrates out of equilibrium. As a consequence, huge amounts of methane may be released to the atmosphere and accelerate the greenhouse effect due to feedback. In general hydrate is not stable towards typical sandstone and will fill pore volume rather than stick to the mineral walls. This implies that if there are imperfections and leakage paths in the sealing mechanisms the hydrate reservoir will leak. There are numerous small and large leaking hydrate reservoirs which results in methane fluxes into the ocean. Some of these fluxes will be reduced through consumption in biological ecosystems or chemical ecosystems. The net flux of methane reaching the atmosphere per

year is still uncertain. Methane is by far a more powerful greenhouse gas than CO2 (~20 times). hypothesized that major release from methane hydrate caused immense global warming 15 000 years ago. This theory, referred to as “clathrate gun” hypothesis is still regarded as controversial, but is supported in a very recent paper by Kennedy et al. (2008). The role of gas hydrate in global climate change is not adequately understood. For hydrate methane to work as a greenhouse gas, it must travel from the subsurface hydrate to the atmosphere. Rates of dissociation and reactions/destruction of the methane gas on its way through sediment layers, water and air are uncharted.

  1. Geomechanical Stability

Gas hydrates will affect the seafloor stability differently for the different types of hydrate occurrences. All of these hydrate configurations may take part of the skeleton framework that supports overlying sediments, which in turn is the fundament for pipelines and installations needed for production. These concerns have already been established for oil and gas exploitation where oil and gas reservoirs that lie below or nearby hydrate bearing sediments. However, geohazards would potentially be far more severe if gas hydrate is to

be produced from marine hydrate deposits. During melting, the dissociated hydrate zone may lose strength due to under-consolidated sediments and possible over-pressuring due to the newly released gas. If the shear strength is lowered, failure may be triggered by gravitational loading or seismic disturbance that can result in submarine landslides

Several possible oceanic landslides related to hydrate dissociation are reported in the literature. Among these are large submarine slides on the Norwegian shelf in the North Sea  and massive bedding-plane slides and slumps on the Alaskan Beaufort Sea continental margin.

Production of CH4 from hydrates by CO2 exposure

Thermodynamic prediction suggests that replacement of CH4 by CO2 is a favourable process. This section reviews some basic thermodynamics and earlier experimental studies of this CH4-CO2 reformation process to introduce a scientific fundament for the experimental work presented later in this chapter.

Thermodynamics of CO2 and CH4 Hydrate

CO2 and CH4 form both sI hydrates. CH4 molecules can occupy both large and small cages, while CO2 molecules will prefer the large 51262 cage. Under sufficiently high pressures or low temperatures both CO2 and CH4 will be stable, but thermodynamic studies suggest that CH4 hydrates have a higher equilibrium pressure than that of CO2 hydrates for a range of temperatures. A summary of these experiments is presented in Sloan & Koh,

shows the equilibrium conditions for CO2 and CH4 hydrate in a P-T diagram. This plot is produced using the CSMGem software (Sloan & Koh, 2008), which supplies the most recent thermodynamic predictions.

CO2-CH4 exchange in bulk

Based on the knowledge of increased thermodynamic stability it was hypothesized that CO2 could replace and recover CH4 molecules if exposed to CH4 hydrate .

Several early researchers investigated the CO2-CH4 exchange mechanism as a possible way of producing methane from hydrates. These studies emphasized the thermodynamic driving forces that favour this exchange reaction, though many of the results showed significant kinetic limitations. Many of these early

studies dealt with bulk methane hydrate samples placed in contact with liquid or gaseous CO2, where available surfaces for interaction were limited., studied the CO2-CH4 exchange process in a high pressure cell using powdered CH4 hydrate and then exposed it to CO2. They observed a fairly rapid initial conversion during the first 200 minutes, which then slowed down significantly. found remarkable recovery of methane hydrate by using CO2 and N2 mixtures. They found that N2 would compete with CH4 for occupancy of the smaller sI cages, while CO2 would occupy only the larger sI cage – without any challenge of other guests. They also found that sII and sH would convert to sI and yield high recoveries (64-95%) when exposed to CO2 or CO2-N2 mixtures.

An inherent limitation in this experiment is the absence of mineral surfaces and the corresponding impact of liquids that may separate minerals from hydrates. These liquid channels may serve as transport channels as well as increased hydrate/fluid contact areas.

CO2-CH4 Exchange in Porous Media

Lee et al., 2003 studied the formation of CH4 hydrate, and the subsequent reformation into CO2 hydrate in porous silica. CH4 hydrate was formed at 268 K and 215 bar while the conversion reaction was studied at 270 K. The temperatures in the ice stability region could have an impact on the reformation mechanisms since ice may form at intermediate stages of opening and closing of cavities and partial structures during the reformation. Temperatures below zero may also have an impact in the case where water separates minerals from hydrates. Preliminary studies of the CO2 exchange process in sediments showed slow methane production when the P-T conditions were near the methane hydrate stability and at CO2 pressure values near saturation levels .The research presented below revisit the CO2- CH4 exchange process in hydrates formed in porous media, this time in larger sandstone core plugs and well within the hydrate stability for both CO2 and CH4 hydrate, and outside the regular ice stab

References:
1. Gas Treating – Absorption Theory and Practice – DAG A. EIMER
2. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

Natural Gas Dehydration Part.2

PROCESS DESCRIPTION OF GAS DEHYDRATION
The principle of glycol dehydration is contacting a natural gas stream with a hygroscopic liquid which has a greater affinity for the water vapor than does the gas. Contactor pressure is subject to economic evaluation usually influenced by water removal duty, required water dewpoint, vessel diameter and wall thickness. After contacting the gas, the water-rich glycol is regenerated by heating at approximately atmospheric pressure to a temperature high enough to drive off virtually all the absorbed water. The regenerated glycol is then cooled and recirculated back to the contactor.

Triethylene glycol (TEG) is the most commonly used dehydration liquid and is the assumed glycol type in this process description. Diethylene glycol (DEG) is sometimes used for uniformity when hydrate inhibition is required upstream of dehydration or due to the greater solubility of salt in DEG. Tetraethylene glycol (TREG) is more viscous and more expensive than the other glycols. The only real advantage is its lower vapour pressure which reduces absorber vapor loss. It should only be considered for rare cases where glycol dehydration will be employed on a gas whose temperature exceeds about 50 °C, such as when extreme ambient conditions prevent cooling to a lower temperature.
TEG has been applied downstream of production facilities that use MEG or DEG as a hydrate inhibitor without apparently leading to contamination problems. Methanol used as a hydrate inhibitor in the feed gas to a glycol dehydration unit will be absorbed by the glycol, and according to the GPSA Engineering Data Book it can pose the following problems:
– methanol will add additional reboiler heat duty and still vapor load and therefore increase glycol losses;
– aqueous methanol causes corrosion of carbon steel. Corrosion can thus occur in the still and reboiler vapor space;
– high methanol injection rates and consequent slug carry-over can cause flooding.
Where there is upstream hydrate inhibition, credit should be taken for any favorable reduction in the water content of the vapor phase. This effect is less significant at lower
feed temperatures, i.e. equivalent to about 2 °C reduction in water dewpoint at 10 °C feed temperature at 9 MPa pressure and 60 percent by weight MEG in the aqueous phase.
Adherence to the recommendations in this DEP can minimize but not eliminate entrainment and vapor losses of glycol. Glycol entrainment may lead to the following downstream problems:
– coalescing and partial condensation in pipelines resulting in localised corrosion;
– in cryogenic plants, particularly at temperatures below -25 °C, freezing of TEG and plugging of equipment;
– reduced performance of downstream adsorption plant, e.g. molecular sieves or silica gel.
Any entrained glycol should be removed upstream of cryogenic plant in high efficiency gas/liquid separators to prevent possible plugging. A range of lean TEG concentrations can be achieved with the basic regeneration flow.

References:
1. Gas Dehydration Field Manual, Maurice Stewart & Ken Arnold
2. Gas Dehydration by TEG and Hydrate Inhibition Systems, Arthur William
3. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish