GMS Interneer oil & gas equipment users in Thailand

[ธนัส]

Designs for Cryogenic Tanks

Liquid-storage vessels
Liquid hydrogen (LH2) is typically stored in cylindrical tanks. Spherical tanks can carry a significant amount of liquid. Cryogenic tanks are vacuum insulated to minimize evaporation losses and contain redundant pressure release mechanisms to prevent over-pressurization. Liquid hydrogen tanks typically operate at pressures of up to 850 kPa (123 psi).

The pressure release system will function at a maximum pressure of 1,035 kPa (150 psi) in most tanks. Even if hydrogen is not drawn from the tank, LH2 evaporation will occur, and the resulting pressure will be released on a regular basis by the pressure relief mechanism as part of normal operation.

Cryogenic tanks are constructed and manufactured in accordance with well-established norms such as:
             - The US Department of Transportation’s restrictions apply to transportable storage tanks.
             - Transport Canada imposes limitations on mobile storage tanks.
             - Regulations such as the ASME Boiler and Pressure Vessel Code (BPVC) apply to stationary storage tanks.
             - Larger tanks are occasionally designed in line with standards such as API Standard 620, Design and Construction of Large, Welded, Low-Pressure Storage Tanks.
             - Stationary tank supports should be able to resist fire exposure without failing.

The paperwork for each vessel should include a description of the vessel, a list of available drawings or other materials, the most recent inspection results, and the name of the responsible person. Vessels must also be marked in accordance with the applicable regulations. Each cryogenic liquid storage tank (stationary and mobile) should be legibly labeled “LIQUEFIED HYDROGEN – FLAMMABLE GAS.”

A warning labeled “Do not spray water on or into the vent hole” should be displayed on the vessel near the pressure-relief valve vent stack. Local first responders and firefighters should be specially trained in LH2 spill response tactics.

Cryogenic liquids and the containers in which they are stored
Cryogenic tanks are used to safeguard cryogenic liquids. Cryogenic liquids are liquefied gases that have temperatures of -150 °C or below. Byproducts include oxygen, argon, nitrogen, hydrogen, and helium. Cryogenic tanks may also be used to store gases at higher temperatures, such as LNG, carbon dioxide, and nitrous oxide. These are components of gas supply systems used in a number of sectors including metal processing, medical technology, electronics, water treatment, energy generation, and food processing. Low temperature chilling uses using cryogenic liquids include engineering shrink fitting, food freezing, and bio-sample storage.

Cryogenic tanks are thermally insulated and are typically equipped with a vacuum jacket. They are created and manufactured to stringent standards in compliance with international design criteria. They might be fixed, movable, or transportable.

Static cryogenic tanks are designed for permanent usage; however, transportable small tanks on wheels for use in workshops and laboratories are provided. Because static cryogenic tanks are typically classified as pressure vessels, new tanks and their associated systems will be built and installed in accordance with the Pressure Equipment (Safety) Regulations. For applications requiring direct access to the liquid, non-pressurized open neck vessels (Dewar flasks) are also available. The tanks are available in a range of sizes, pressures, and flow rates to meet the different demands of the customers. Tanks used to transport cryogenic liquids must comply with the Regulations on the Carriage of Dangerous Goods and the Use of Transportable Pressure Equipment.

Use, operation, maintenance, and disposal of cryogenic tanks
All applicable regulations, such as the Pressure Systems Safety Regulations for static tanks and the Carriage of Dangerous Goods and Use of Transportable Pressure Equipment Regulations for transportable tanks, must be followed when operating and maintaining cryogenic tanks. Cryogenic tanks must be maintained and operated by trained personnel.

The Regulations require cryogenic tanks to be inspected on a regular basis, as well as routinely maintained and subjected to formal examinations on a periodic basis for static tanks. To ensure that the tank is in safe operating condition between official examination times, an inspection and maintenance program should be created. This will include a Written Plan of Examination, which will be created by a competent person(s), as well as periodic formal examinations conducted in accordance with the scheme.

Transportable tanks must be inspected and tested on a regular basis, which may only be done by an Inspection Body recognized by the National Competent Authority, Department for Transport, in the United Kingdom (DfT). The Vehicle Certification Agency (VCA) website provides information on Examination Bodies that have been assigned to execute various tasks relating to tank and/or pressure equipment inspection. All inspections, examinations, and tests are documented, and these documents must be kept for the duration of the tank’s life.

Cryogenic tank users and owners have legal obligations as well as a duty of care to ensure that their equipment is properly maintained and operated. The user must undertake routine safety inspections. Daily inspections must be carried out. A gas company will only fill a tank if it believes it is safe to do so. While in use, a small amount of icing and ice may be visible. Small levels of ice are not cause for concern, but the quantity of ice should be checked on a frequent basis. To minimize excessive ice collection, de-icing should be conducted if ice continues to accumulate.

Cryogenic tank repair and modification
Any repair or modification to a cryogenic tank should be performed only by a skilled repairer in accordance with the design codes to which it was constructed, while taking current regulations and legislation into account. Such repairs or adjustments must not affect the structural integrity or the operation of any protective systems. All repairs and adjustments must be documented, and the documentation must be kept for the rest of the tank’s life.

Cryogenic tank revalidation
Cryogenic tanks must be assessed on a regular basis to ensure that they are safe to use. The revalidation period, which shall not exceed 20 years, shall be determined by a Competent Person. Mobile tanks should be rented for a shorter period of time due to the nature of their function. When a tank is revalidated, a report is created that must be kept with the tank data for the life of the tank.

Security for Cryogenic Tanks
Liquid oxygen, liquid nitrogen, and liquid argon are examples of cryogenic liquids. Their respective boiling points are as follows:
            - -297.3oF | -183oC • -320.4°F | -195.8°C
            - Liquid Oxygen Nitrogen in liquid form
            - -302.6°F (-185.9°C) Argon Liquid
            - The sublimation point of liquid CO2 is -109.3°F | -78.5°C.
To prevent heat transfer and sustain very low temperatures, the storage vessel must be correctly constructed. The water capacity of commercially available liquid oxygen, liquid nitrogen, and liquid argon storage tanks ranges from 350 to 13,000 US gallons (1,325 to 49,210 liters). The storage tanks for Cryogenic Bulk Tanks may be vertical, spherical, or horizontal, depending on the location and consumption demands.

Cryogenic liquid storage tanks are made up of three major components:
• Vessel of Internal Pressure
A cryogenic vessel made of stainless steel or other materials with high strength when exposed to cryogenic temperatures.

• The Outer Vessel
A vessel made of carbon steel or stainless steel. Under normal operating conditions, this vessel maintains the insulation around the inner pressure vessel and can also maintain a vacuum around the inner vessel. Most of the time, the external vessel is not exposed to cryogenic temperatures.

• Insulation
The vacuum-sealed space between the inner and outer vessels, which is filled with several inches of insulating material. The vacuum and insulating material help to reduce heat transfer and, as a consequence, the boil-off of the liquid oxygen, liquid nitrogen, or liquid argon contained inside the vessel.

The inner vessel of a storage tank is typically designed to sustain a maximum allowed operating pressure of 250 psig (1724 kPa). Vessels may be designed for higher or lower working pressures, as well as for specific uses. The service pressure of the vessel may be adjusted.
https://www.gmsthailand.com/blog/designs-for-cryogenic-tanks/

[ธนัส]

What exactly is steel pipe?

Steel pipe has been manufactured in the United States since the early 1800s. Pipe is a hollow piece having a circular cross- section that is used to convey items such as fluids, gas, pellets, powders, and more. Steel pipes, on the other hand, are employed in a number of applications. They are used to transmit water and gas underground across cities and villages. They are also used in building to safeguard electrical wiring. Steel pipes may be both robust and light. As a result, they are ideal for bicycle frames. They are also utilized in the manufacture of vehicle components, refrigeration equipment, heating and plumbing systems, flagpoles, and street lighting, to mention a few.

The outer diameter (OD) and wall thickness are the two most essential dimensions for a pipe (WT). The internal diameter (ID) of a pipe is determined by OD minus 2 times WT (schedule), which defines the pipe’s liquid capacity. When we speak about pipe in our profession, we usually refer to it by its (ID) and schedule, such as 2-inch schedule 40 or 14 inch extra heavy. Sch. 40, Sch. 80, Sch. Standard (STD), Sch. XS/XH, and Sch. XXS are examples of walls or schedules. The majority of pipe is offered in lengths of 21 or 42 feet.

What exactly is Steel Tube?
The term tube refers to hollow portions that are round, square, rectangular, or oval and are utilized for pressure apparatus, mechanical applications, and instrumentation systems.

Steel tube may be manufactured using a variety of basic ingredients, including iron, carbon, manganese, vanadium, and zirconium. Tubing, like pipe, may be made as either seamless or welded. Seamless tubing is made from a solid piece of steel that is rolled into a circular form before being perforated and stretched to its full length. Consider a wad of play dough and shaping it into a cylinder. Then, using the leftover dough, press your finger into the center and lengthen it. That’s how it’s made, but it’s hot and whirling and all automated. Welded steel tube, on the other hand, is produced from coil. The coil is sliced and rolled into a circular form before the ends are soldered together. From then, the tubing may be cut to a certain length as round tubing or further distorted into different forms such as square, rectangular, oval, and so on.

Tubes are labeled with their outer diameter (OD) and wall thickness (WT), both in inches and millimeters. Buyers in our business often refer to the item they seek as a (OD) and a wall thickness (WT). Wall thicknesses such as 11 gauge, 1/4″, 3/8″ and 5/8″ are examples. Tubing is often available in lengths of 20, 24, 40, and 48 feet, although bespoke lengths are readily made.

Is it a tube or a pipe?
Although the names are often used interchangeably, there is one significant distinction between tube and pipe, notably in how the material is arranged and toleranced. Because tubing is utilized in structural applications, the outer diameter is the most essential dimension. Tubes are often used in applications requiring exact outer diameters, such as medical equipment. The outer diameter is significant because it indicates how much weight it can support as a stability element. Pipes, on the other hand, are often used to carry gases or liquids, therefore knowing the capacity is critical. Knowing how much water can flow through the pipe is critical. The pipe’s round form makes it effective at managing pressure from the liquid running through it.

Classification
Pipes are classified according to their schedule and nominal diameter. Pipe is normally ordered in accordance with the Nominal Pipe Size (NPS) standard, with a nominal diameter (pipe size) and schedule number specified (wall thickness). The schedule number on various sizes of pipe may be the same, but the actual wall thickness will vary.

Tubes are usually ordered by outer diameter and wall thickness, but they may also be ordered by OD & ID or ID and Wall Thickness. The wall thickness of a tube determines its strength. A gauge number specifies the thickness of a tube. Larger outer diameters are indicated by smaller gauge numbers. The interior diameter (ID) is a theoretical measurement. Tubes may be square, rectangular, or cylindrical in form, while pipe is always round. The circular form of the pipe distributes the pressure load equally. Pipes are used for bigger purposes and come in diameters ranging from 12 inch to several feet. Tubing is often utilized in applications that demand lower sizes.

Purchasing Tubing or Pipe
Tubing is usually ordered by outer diameter and wall thickness, but it may also be ordered by OD & ID or ID and Wall Thickness. Although tubing contains three dimensions (O.D., I.D., and wall thickness), only two of them may be defined with tolerances, while the third is purely theoretical. Tubing is often ordered and kept to stricter tolerances and requirements than pipe. Pipe is normally ordered in accordance with the Nominal Pipe Size (NPS) standard, with a nominal diameter (pipe size) and schedule number specified (wall thickness). Tubes and pipes may both be cut, bent, flared, and constructed – see our top 10 ordering advice for tubing and piping.

Characteristics
There are a few fundamental differences between tubes and pipes:
- Shape
Pipe is usually circular in shape. Tubes come in square, rectangular, and circular shapes.

- Measurement
Outside diameter and wall thickness are frequently selected when ordering tubes. Tubing is often held to stricter tolerances and requirements than pipe. Pipe is commonly ordered using the nominal pipe size (NPS) standard, with the nominal diameter (pipe size) and schedule number specified (wall thickness)

- Capabilities for Telescoping
Telescopes may be used on tubes. Telescoping tubes are ideal for applications that need many pieces of material to be sleeved or expanded within one another.

- Rigidity
Pipe is unyielding and cannot be shaped without the use of specialized tools. Tubes can be shaped with considerable effort, with the exception of copper and brass. Tubing can be bent and coiled without causing severe deformation, wrinkling, or breaking.

- Applications
Tubes are employed in applications that need a precise outer diameter, such as medical equipment. The outer diameter is significant because it indicates how much weight it can support as a stability element. Pipes are used to transfer gases or liquids, therefore knowing their capacity is critical. The pipe’s round form makes it effective at managing pressure from the liquid running through it.

- Metal Forms
Tubes may be cold or hot rolled. Only hot rolled pipe is available. They may both be galvanized.

- Sizing
Larger applications may be accommodated by size pipes. Tubing is often utilized in applications requiring tiny diameters.

- Strength
Tubes are more durable than pipe. Tubes outperform other materials in situations requiring durability and strength.

Types of steel pipe fittings
Pipe fittings are constructed from a variety of steels, including:
            - Galvanized Steel: Galvanized steel is coated with layers of zinc by a chemical process to protect it against rust and corrosion. Galvanized steel is resistant to rust and corrosion and is widely used in the manufacture of pipe fittings and pipe. Galvanized steel also extends the life of pipe fittings. Galvanized steel fittings are offered in conventional diameters ranging from 8mm to 150mm. Galvanized pipe fittings are often made from seamless tube, forgings, rolling bar, or welded tube in accordance with particular specifications. Galvanized steel pipe fittings are used for all sorts of pipes inside a structure. They are also used in water distribution lines, but not in gas pipes.
            - Carbon Steel: Carbon steel is far more durable and stronger than other types of steel, making it ideal for the manufacture of pipe fittings. Carbon steel, often known as simple carbon steel, is a malleable iron-based metal that contains mostly carbon and trace quantities of manganese and other metals. Steel may be cast to shape or worked into different mill forms from which final products are made, forged, stamped, machined, or otherwise shaped. Carbon is the primary hardening and strengthening ingredient in steel, providing maximum hardness and strength but decreasing ductility and weldability. Carbon steel pipe fittings are available in a variety of sizes and forms. Again, there are certain butt-weld carbon fittings with beveled edges that produce a shallower channel for the bead of weld that holds the component together. Butt-weld fittings are primarily utilized to link pipe sections when permanent and welded connections are needed. Butt-weld steel fittings are used to make elbows, reducers, tees, and other similar items. Carbon steel fittings are used in pipe systems that transport liquids or gases such as oil, water, natural gas, or steam. Aside from that, carbon steel fittings are in great demand in residential construction, commercial construction, electric power generation, petroleum refining, shipbuilding, and other industrial-use industries.
            - Stainless steel: Because it is extremely resistant to oxidation and corrosion in a variety of natural and man-made settings, stainless steel is frequently utilized in the manufacture of pipe fittings. Stainless steel is a ferrous alloy that contains at least 10% chromium. It is critical to choose the correct grade of stainless steel for a certain application. Stainless steel is used in a variety of pipe fittings such as tees, unions, elbows, and so on. Household pipes are often fitted with stainless steel fittings.
https://www.gmsthailand.com/blog/what-exactly-is-steel-pipe/

[ธนัส]

An Overview of Cogeneration Operations

What Is the Process of a Cogeneration Plant?
When a power plant creates electricity, it also generates heat. If the plant emits that heat into the atmosphere as exhaust, it constitutes a massive waste of energy. The majority of the heat may be collected and reused. When heat is repurposed, the power plant operates as a cogeneration system.

The cogeneration process may improve total energy efficiency, with typical systems achieving efficiency levels ranging from 65 to 90 percent. Businesses that employ cogeneration may reduce greenhouse gas emissions and pollutants while lowering operating costs and increasing self-sufficiency.

The History of CHP
Thomas Edison, widely regarded as America’s greatest inventor, planned and completed Pearl Street Station in New York City in 1892.

The idea of combining heat and electricity is not new. CHP was utilized in Europe and the United States as early as 1880 to 1890. Many companies employed their own coal-fired power plants to create the energy that powered their mills, factories, or mines during those years.

As a byproduct, the steam was utilized to provide thermal energy for different industrial operations or to heat the area.

In 1882, Thomas Edison planned and constructed the first commercial power plant in the United States, which also occurred to be a cogeneration facility. The thermal waste of Edison’s Pearl Street Station in New York was sent as steam to local factories, as well as heating neighboring buildings.

The Rise and Fall of CHP Utilization
CHP systems provided around 58 percent of the total on-site electrical power generated in industrial enterprises in the United States in the early 1900s. According to “Cogeneration: Technologies, Optimization, and Implementation,” edited by Christos A. Frangopoulos, that number had dropped to barely 5% by 1974.

There were several explanations for the precipitous drop.
Electricity from central power grids grew more dependable and less expensive to purchase, while fuel, such as natural gas, became more affordable, making privately owned coal-fired on-site power plants less appealing. In addition, the government raised the quantity and scope of rules and limitations pertaining to power generating. However, as fuel prices surged in 1973 and public awareness of the detrimental impacts of pollution expanded, cogeneration regained prominence.

Why Should You Use Cogeneration?
Cogeneration has a number of advantages. The primary motivations for using CHP are to save energy and money by lowering fuel use. Existing CHP customers in the United Kingdom, for example, save 20% on their energy bills.

When fuel energy is turned into mechanical or electrical energy via CHP, the majority of the heat emitted is not squandered. Less fuel is required to perform the same quantity of productive work as a typical power plant.

This lower fuel consumption has various advantages, including:
         - Reduced gasoline expenses
         - Fuel storage and transportation requirements are reduced.
         - Emissions reduction — CHP is one of the most cost-effective methods of reducing carbon emissions.
         - Machine wear is minimized as a result of reduced pollution exposure.
         - Another advantage is security.

Cogeneration is regarded as a secure power source since it produces stand-alone electricity that is not reliant on a municipal power system. A cogeneration-powered firm may operate off-grid or simply supplement to meet a rise in power demand.

The Basic Elements of a Cogeneration Plant
A typical cogeneration facility, at its most basic, consists of an electricity generator and a heat-recovery system. Here are some fundamental components of a CHP system:
          - Prime movers: These machines convert fuel into heat and electrical energy, which may then be utilized to create mechanical energy. Gas turbines and reciprocating engines are examples of primary movers.
          - Mechanical energy is converted into electrical energy by an electrical generator.
          - System of heat recovery: Heat is captured from the primary mover.
          - Heat exchanger: Ensures that the collected heat is used.

What Are the Fuels Used in Cogeneration Plants?
Cogeneration facilities may run on a range of fuels, including natural gas, diesel, gasoline, coal, and biofuels.

Biofuels used in cogeneration are generally produced from renewable resources such as landfill gas and agricultural solid waste.

CHP systems are classified into two kinds.
          - Cycle plants at the top: The production of power is the first step in a topping cycle system.
         - Plants in the bottoming cycle: The first step is to create heat – waste heat generates steam, which is subsequently utilized to generate electricity.

Bottoming cycle plants may be found in businesses that employ very hot furnaces. They are less prevalent than topping cycle plants, because to the ease with which surplus power may be sold.

Who Can Benefit from Cogeneration?
Heat and electricity are in high demand in the industrial sector. Metal makers, for example, largely employ heat, while others mostly use electricity. Other businesses need varied amounts of heat and power.

A recycled energy system may help in any circumstance. A factory that uses more heat than electricity may sell the heat to a utility, and surplus power can be sold in the same way.

There are three sizes of cogeneration plants:
            - Small: The military, colleges, and non-utility corporations run several small CHP plants in the United States and Canada. What they have in common is a strong demand for energy, as well as a pressing need for dependable and self-sufficient energy sources. According to a Scientific American article, a computer networking firm that uses CHP saves roughly $300,000 in energy expenditures each year.
           - Medium: The market for medium-scale cogeneration systems is expanding. According to David Flin’s “Cogeneration: A User’s Guide,” medium-scale units produce 50 to 500 kW of electricity. This category includes industries that demand significant heat and energy loads, such as hospitals and hotels.
           - Large: Large CHP plants may be found in energy-intensive industries like as oil refineries and food processing plants. These may generate 500 kW or more of electricity.

Cogeneration makes sense when the necessary circumstances are met. It’s a dependable and efficient solution to offer on-site electricity that’s both inexpensive and ecologically friendly.

A thorough knowledge of steam-urbine operating and power generating costs may aid in increasing total cogeneration profitability. This article explains the fundamental economics of cogeneration.

Cogeneration enables a facility to lessen its dependency on external electrical energy purchases by utilizing steam to spin turbines and create electricity. This article outlines best practices for steam cogeneration system selection, operation, integration, and control.
https://www.gmsthailand.com/blog/overview-of-cogeneration-operations/

[ธนัส]

LNG Plant Safety

The use of natural gas as a cleaner-burning alternative to other fossil fuels is becoming more popular as the globe works toward decarbonization. Natural gas may be converted to liquefied natural gas (LNG) for storage and transportation purposes, which is safer. Facilities that handle LNG, such as liquefaction plants, regasification plants, and storage facilities, are still connected with the possibility of injury or death from the gas. Understanding these dangers is critical to putting in place the required preventative and mitigation measures to protect people and property.

When it comes to LNG plants, an uncontrolled leak of a cryogenic, poisonous, or combustible fluid is a major concern. Releases of this kind might originate in a variety of locations within the industrial system. When these releases occur, the consequences are determined by what they expose and whether or not they are ignited. For the sake of simplicity, the most significant LNG plant risks may be divided into seven categories.

Natural gas liquids (LNG) take up just 1/600th of the volume of natural gas in its gaseous condition, but they maintain all of the energy potential. As a result, the energy potential of a certain volume of LNG is much larger than the energy potential of a same amount of natural gas in its gaseous condition. The intrinsic features of LNG, as well as the design and operation of LNG facilities and transportation modes, are all taken into consideration when addressing the safety of LNG facilities.

Land-based LNG facilities use impoundment structures surrounding LNG tanks and pipes, which are intended to limit the spread of LNG in the event of an accidental leak. When a release occurs, fire and vapor suppression devices are installed in order to limit the repercussions of the event. Automated fire suppression and vapor suppression systems are activated by gas detectors, fire detectors, temperature sensors, and other sensors. Firefighters may employ water spray to cool heat-affected exposures, or high-expansion foam to lessen the effect of radiant heat on certain exposures in the case of a fire. Vapor fences are constructed at certain sites to prevent fumes from escaping and spreading to neighboring property boundaries. In addition, vacuum jacketed pipe offers an extra layer of protection in the event that the inner pipe ruptures. When operating parameters exceed the usual range, emergency shutdown mechanisms are activated to prevent further damage. The operator of an LNG plant must establish and adhere to thorough maintenance protocols in order to maintain the integrity of the facility’s different safety measures.

Prior to beginning operations, the LNG plant operator must develop precise operating procedures that outline the usual operating parameters for all of the facility’s machinery. Any time a piece of equipment is upgraded or replaced, all associated processes must be examined and, if required, adjusted in order to maintain the system’s integrity. All staff are required to undergo training in operations and maintenance, security, and firefighting before they may begin working. Coordination with local authority and informing them of the sorts of fire control devices accessible inside the facility are essential tasks for an owner or operator. Aside from that, federal requirements need a high level of security for the facility, which includes access control systems, communications systems, enclosure monitoring, and patrolling.

Risks associated with LNG installations include:
Temperature
           - It is possible to have cryogenic liquid releases that induce embrittlement if they come into contact with materials that are not intended to manage such releases, and freeze burns if they come into contact with persons.
           - Turbines, boilers, and engines generate electricity and heat by releasing hot vapor into the atmosphere.

Toxic
           - gas emissions such as hydrogen sulfide (H2S) or ammonia are a concern.

Asphyxiation
           - Releases of nitrogen oxide, carbon monoxide, carbon dioxide, or sulfur dioxide that replace oxygen in an area and may result in asphyxiation are classified as asphyxiation.

Pool Fire
           - Liquid discharges that collect in a pool on the ground or in water and ignite, resulting in a pool fire that might burn for hours or days.

Jet fire
           - Pressurized gas or liquid is released and ignites, resulting in a high heat flux jet fire with a fast rate of spread.

Vapor dispersion/flash fire
           - Gas or liquid discharges that cause a flammable cloud to build in an open area and then ignite, resulting in a brief and powerful flash fire that is hazardous to the surrounding environment.

Explosion of a vapor cloud (VCE)
           - An explosion and pressure wave are caused by the discharge of gas or liquid, which causes a flammable cloud to build in a crowded or confined region and then ignites.

Research and Studies about LNG Safety
Through its Pipeline Safety Research and Development programs, the Federal Highway Administration (PHMSA) sponsors LNG research. The following LNG projects are underway:
           - DTRS56-04-T-0005, Modeling and Assessing a Spectrum of Accidental Fires and Risks in an LNG Facility.
           - DTPH5615T00005, Comparison of Exclusion Zone Calculations and Vapor Dispersion Modeling Tools.
           - DTRS56-04-T-0005, Modeling and Assessing a Spectrum of Accidental Fires and Risks in an LNG Facility.
           - DTPH5615T00008, Statistical Review and Gap Analysis of LNG Failure Rate Table (Statistical Review and Gap Analysis of LNG Failure Rate Table)

An Overview of the History of Vapor Cloud Explosions (VCE)
The recent availability of domestic shale gas has resulted in the construction of LNG export facilities that will be able to liquefy massive amounts of natural gas. When it comes to liquefying natural gas, these facilities need substantially bigger volumes of refrigerants than are generally required in peak shaving or small-scale operations. ethane, propane, ethylene, and iso-butane are among the heavy hydrocarbons found in most refrigerants gases and mixes used in export facilities, and they are referred to as heavy hydrocarbons. These gases are comparable to gases that have caused VCEs at petrochemical sites in the past. However, the Pipeline and Hazardous Materials Safety Administration (PHMSA) is not aware of any valid reports of outdoor natural gas vapor cloud explosions and does not think that there is a danger of vapor cloud explosions (VCEs) owing to the emission of methane in an open area.

The Review of Vapor Cloud Explosion Incidents report was sponsored by the Pipeline and Hazardous Materials Safety Administration (PHMSA) with the primary goal of improving scientific understanding of vapor cloud development and explosion in order to more reliably assess hazards at large liquid natural gas (LNG) export facilities. We must emphasize that the LNG export facilities in operation today have several levels of security in place that were not in place at the sites described in the study. Many of the lessons learnt from these incidents have resulted in the implementation of safety measures that are now needed in LNG installations. Specifically, the purpose of reviewing the specific incidents in this report is to examine the extensive forensic evidence that is available, which provides the information necessary to investigate how the vapor cloud formed and ignited, the amount of overpressure exerted, and other information about the mechanism of VCE.
https://www.gmsthailand.com/blog/lng-plant-safety/

[ธนัส]

LNG Plant Commissioning Process

Commissioning
What is the process of commissioning?
In some ways, the commissioning process may be seen of as a quality assurance procedure that allows the construction project teams to produce a building that is fully operational and meets all of the specifications. This is a critical contrast between the delivery of a physical structure and the delivery of a facility in complete operating order that is really functional for persons, companies, and the environment as a whole.

The idea of full functioning order necessitates the completion of a number of goals, and there are several elements that influence the performance of a structure and its engineering services in general. Design characteristics that will allow for verification activities such as functioning, pressure testing, and flow regulation are included into the process in general. Procedures that will cover prescribed settings to work, system regulation, and performance testing are also included. The commissioning process must also include user and operator training, as well as the creation of critical system documentation, in order to properly support building operation and usage in the future.

Stages of the commissioning process
In the commissioning process, there are eight steps, which are as follows: preparation, design, pre-construction, construction, commissioning of services, pre-handover preparation, first occupation preparation, and post-occupancy care.

A building’s actual energy consumption in the first year might be up to 25 percent greater than the estimate made during the design stage, and this is ascribed to insufficient commissioning and handover procedures during construction. doing the task successfully

All of the steps listed above, as well as beginning the commissioning process as soon as feasible, assure cost-effective project completion while also allowing the building’s inhabitants to optimize equipment utilization long after the construction process is complete, according to the manufacturer.

The following is a summary of the actions that were carried out at each stage:
Stage 1 – Planning and Preparation:
         - Assemble the commissioning team.
         - Examine lessons learned and experiences gained from similar buildings and projects.
         - Clearly define the performance outcomes expected by the client and the end user.
         - Contribute to the development of a design brief that accurately represents the required performance

Stage 2 – Design:
         - Review the performance results with the client
         - Ensure that the commissioning process activities have been clearly established
         - Ensure that the performance outcomes reflect any modifications to the system/project design

Stage 3 – Pre-Construction:
         - Ensure that the contractors understand the performance requirements.
         - Verify that the trade contractors have the capability to satisfy the requirements of the commissioning process.

Stage 4 – Post-Construction:
         - Develop a thorough commissioning program.
         - Carry out pre-commissioning work, which includes checking the installation work and running static tests. Verify and record that the desired performance objectives have been met.
         - Ensure that progress on the creation of the O&M manuals is made on a consistent basis.


Stage 5 – Commissioning of Engineering Services:
         - Perform the initialization of systems and ensure that they are operational.
         - Verify that the necessary performance and outcome objectives have been met or exceeded.
         - Performance testing of the building, equipment, and engineering services should be carried out. Make that the specified performance levels have been met and record this in writing.
         - Include members of the facilities management team in the commissioning process.
         - Gather all of the commissioning checklists and test papers in one place.

Stage 6 – Preparation for Handover
         - Examine the quality of the documentation evidence gathered throughout the commissioning process’s activities.
         - Maintain completeness and accuracy of all necessary statutory paperwork.
         - Provide users and operators with instruction and guidance.
         - Create and distribute user manuals for the building.
         - Examine the needs of the customer and respond to any discrepancies.

7. Initial Occupation:
         - Introduce the user to their equipment or premises and demonstrate how it works.
         - Assist the facilities management team with the earliest phases of the building’s operation
         - Refresh commissioning records in line with and after approval of any revisions
         - Update the operation and maintenance manuals to reflect any modifications that have been authorized.

Stage 8 – Post-occupancy care
         - Seasonal commissioning.
         - Fine tuning of the building and its engineer services.
         - Building performance evidence is collected and reviewed.
         - Commissioning records and operation and maintenance manuals are updated in accordance with seasonal commissioning and fine-tuning work.
         - Lessons learned are produced by comparing building performance to design intent, client stakeholder expectations and industry benchmarks.

Documentation for the commissioning and transfer of services
Building handover information is incomplete without the inclusion of commissioning process verification and test records, which are crucial components of the handover information. It is not only important to have proof that the desired performance objectives have been reached, but it is also important to have knowledge about the method in which the system has been configured for operation in case any enhancement, modification, or fine-tuning work is needed after handover.

The summary commissioning process is the post-installation procedure that occurs prior to the start-up and operation of the system. It assures that the equipment that has been installed and linked will operate at peak efficiency from the beginning, while also validating that the performance of the LNG equipment has been reached. It is possible to complete this procedure on site at the client’s option, and it includes a complete system assessment and optimization, as well as staff training and demonstration, as well as supporting documentation to support equipment usage now and in the future.

Starting up and commissioning your natural gas processing facility is a time-consuming process.
Start-up and commissioning are the last stages of preparations required before a natural gas processing plant or comparable processing facility can be put into production. The operations carried out throughout the start-up and commissioning phases should guarantee that the facility will function safely and in accordance with its design specifications and specifications.

The majority of EPC turnkey contracts include this phase as part of the overall package. Engineers, field technicians, and operations people will comb over every inch of the plant, inspecting hundreds of connections, instruments, valves, and other pieces of equipment. This time- and labor-intensive procedure will take many months. Depending on how sophisticated the facility is, it might take weeks or even months to finish.
https://www.gmsthailand.com/blog/lng-plant-commissioning-process/

[ธนัส]

LNG Plant Maintenance and Integrity

What does the term “asset integrity” means in oil and gas industry?
Asset integrity, also known as asset integrity management systems (AIMS), is the term used to describe an asset’s ability to operate efficiently and accurately while also protecting the health and safety of all personnel and equipment with which it interacts – as well as the measures in place to ensure the asset’s long-term availability. Throughout the life cycle of an asset, from its conception through decommissioning and replacement, asset integrity must be maintained.

Asset integrity management consists of a number of components
Much of the oil and gas industry’s infrastructure is already nearing or has already reached the end of its operational life expectancy, if not already beyond it. Because the cost of replacing assets, as well as the resulting turnaround time, has become unacceptably expensive for so many facilities, asset integrity has now surpassed concepts such as OPEX and Agile as the watchword on everyone’s lips, according to a recent study.

There is an increase in challenges such as vessel inspection, which is a significant contributor to production downtime; and corrosion under insulation, which is a frequent cause of sudden shutdowns; and taking the step to employ new solutions is becoming a necessity in many locations, particularly offshore.

The importance of the human factor
Asset integrity is based on the assumption that the vast majority of people within the organization will carry out their responsibilities correctly. However optimistic this may sound, the vast majority of maintenance, inspection, and data management activities are carried out with the best of intentions. Things, on the other hand, are not always accomplished completely or in the shortest amount of time available. It is unlikely that simple measures, such as increased inspection frequency, can uncover every overlooked problem. It is also unlikely that employees, who are required to increase their inspection labor or who are involved in missed problems, will be enthused about the task at hand.

Some indicators that everything is not well in the field of asset integrity management and inspection include the following:
          - Teams believe that any concerns they have regarding health and safety, or the condition of equipment are not taken seriously, resulting in an atmosphere where errors are not even reported as a result of this perception.
          - Any modifications to asset integrity plans, or even the fundamental operation of the facility, are only implemented after a large-scale event.
          - An inability to distinguish underlying causes from basic defect reports, which often leads to personnel being lulled into an unwarranted feeling of security and overstating the extent to which the facility is safe and operating.
          - Tactic knowledge, rather than a physical and immediately available set of rules, is relied upon in the context of AIM and reporting problems.
          - In the world of maintenance contractors, there is a “lowest bidder” mentality that prevails, and knowledge of and passion for asset integrity are not highly rewarded.

The very real outcome of this kind of environment is that nothing occurs in any meaningful way. Till a significant occurrence forces an organization to adjust, which is typically at tremendous expense, asset integrity is seen as a barely acceptable inconvenience, a type of obstacle to getting the job done properly.

Identifying and filling up the gaps in asset integrity management systems
Despite the fact that there are more AIM systems on the market now than at any previous time in history, there are still no one-size-fits-all solutions available. Although no inspection plan or database can possibly address all of the AIM concerns that might occur, integrity systems are nevertheless seen as distinct from the rest of the organization’s activities. Employees may be reluctant to accept responsibility for their actions, seeing the suite of AIM packages as an effort by the corporation to police them rather than as an intrinsic part of their job description.

The holes in AIM packets must be filled with the vigilance of the same persons from whom they are intended to protect, but a creative strategy may be required to guarantee that this message is received by the intended recipients.

What is the significance of asset integrity management?
A leak from the Piper Alpha oil platform in the North Sea occurred over the period of 22 minutes on July 6, 1988, causing an explosion that killed 167 of the rig’s 229 employees. The leak occurred over the length of 22 minutes. Among other things, this accident is seen as a watershed point in the development of current approaches to both EH&S and AIM in the oil and gas industry, not least because it resulted in each offshore operator investing £1 billion in safety measures.

The United Kingdom government subsequently launched a public enquiry, which was completed in 1990 and made 106 recommendations on how to implement HS&E and AIM initiatives more effectively in the future –  all of which were approved by the oil and gas sector. So, given that we are living and working in an era when significant AIM attempts are being made, what areas should individuals be concentrating their energies on?

Developing a strategic approach to AIM
According to research performed by Oil & Gas IQ, oil and gas operators are increasingly pursuing price-responsive strategies as well as the optimization of existing assets in order to remain competitive. These enterprises, particularly those operating in the North Sea, are now re-evaluating their business processes in order to stay afloat. 51 percent of oil and gas experts are now working on installations that are more than 20 years old and have been in service for more than a decade — with fewer than a third working on installations that are in their first ten years of operation.

More than half of asset integrity professionals have had their budgets reduced, and the average grade given to those professionals’ own firms’ asset integrity management (AIM) rating was 5.4 out of a possible 10. Only 52% of respondents believed that their job load was manageable in terms of achieving objectives and preserving safety –  despite the fact that the vast majority worked with a meager budget of less than £250,000. Unsurprisingly, asset integrity professionals report that the two most pressing concerns they face are keeping assets under budget and the age of the assets themselves. The lack of communication between departments in oil and gas businesses is by far the most serious fault that has been identified, followed by a lack of a safety culture in the industry. There is definitely work to be done.

RBI: Risk-Based Inspection
It is now more necessary than ever to ensure that an effective system of identification is in place, especially since the industry’s infrastructure is rapidly aging and becoming one of its key issues. For example, more than half of pipelines in the United States are at least 50 years old, with 3,300 incidents, including the worst spill in US pipeline history, eighty fatalities and almost 400 injuries in only the last five years. Despite the fact that it may seem apparent, maintaining integrity, preventing corrosion, and repairing damage is similar to seeing an iceberg from a distance.

It is nearly impossible to implement damage mitigation techniques without the assistance of dedicated and experienced professionals. For every readily apparent symptom of corrosion or asset instability, there are dozens of hidden issues: hydrogen attack, high-temperature tempering, thermal fatigue, metallurgy issues, internal system corrosion, and so on. Once it has been determined that a comprehensive examination is required, the following step is to put it into effect.

Among the methods available are risk-based inspections (RBIs), which demand that the risk be reduced while putting in the least amount of work possible in order to expedite the process and free up more time. The problem is that there are an almost limitless number of methods in which we may carry out our maintenance – and with so many hazards (such as calibration uncertainty or equipment accessibility), quantification is just not viable. In order to determine where on the quantitative/qualitative spectrum a corporation is located, it must first choose whether it will depend more heavily on specialists or on data.

Companies will operate in either a reactive or a proactive mode, depending on how effectively or poorly they foster their dependability cultures. It goes without saying that you want to be proactive. Because of a failure to foresee and monitor for hidden difficulties, you will only be able to respond after problems have developed, which will cost you significantly more money in the long run and reward those who have shown the ability to react swiftly. Instead of enhancing the culture, this positive reward serves to promote the tendency to react rather than act.
https://www.gmsthailand.com/blog/lng-plant-maintenance-and-integrity/

[ธนัส]

Energy Development: Oil & Gas from start to finish

Due to their position as the world’s principal fuel sources, oil and natural gas are important sectors in the energy industry and have a significant impact on the global economy. The processes and systems involved in the production and distribution of oil and gas are very complicated, capital-intensive, and reliant on cutting-edge technology to function properly. History has shown that natural gas is closely associated with oil, mostly due to the production process or the upstream part of the industry. Natural gas was seen as a nuisance throughout most of the industry’s history, and it continues to be flared in huge amounts in various regions of the globe, notably the United States, even now. Natural gas has risen to a more significant position in the world’s energy supply as a result of the shale gas production in the United States, as previously noted, as well as the fact that it emits less greenhouse gases when combusted as compared to other fuels such as oil and coal.

There are three main segments in the industry, which are as follows:
         - Upstream – refers to the business of oil and gas exploration and production, as opposed to downstream.
         - Midstream process – Transportation and storage
         - Downstream – activities include refining and marketing.
With an estimated $3.3 trillion in revenue generated yearly, the oil and gas business is one of the world’s biggest industries in terms of monetary value, ranking second only to manufacturing. Oil is critical to the global economic framework, particularly for the world’s top producers, which include the United States, Saudi Arabia, Russia, Canada, and China, as well as other countries.
If you are an investor seeking to get into the oil and gas business, you may be intimidated by the intricate vocabulary and specific measurements that are utilized across the industry. This introduction is intended to assist anybody interested in learning about the foundations of organizations operating in the oil and gas industry by introducing essential ideas and measurement standards used in the industry.

About Hydrocarbons
Crude oil and natural gas are made up of hydrocarbons, which are naturally occurring compounds found in the earth’s crust and rock formations. They are formed by the compression of plant and animal remnants in sedimentary rocks such as sandstone, limestone, and schist. These organic raw materials are used in the production of plastics and other manufactured products.

As a result of sedimentary rock formation in ancient seas and other bodies of water, the sedimentary rock itself may be described as follows: The rotting carcasses of plants and animals were incorporated into the developing rock when layers of silt were formed on the ocean bottom. After being subjected to appropriate temperatures and pressure ranges deep under the earth’s crust, the organic material finally converts into oil and gas.

Being lighter in weight than water, oil and gas move more quickly through permeable sedimentary rock toward the earth’s surface than water. The formation of an oil and gas reservoir occurs when hydrocarbons are trapped behind less-permeable cap rock. We get our crude oil and natural gas from these oil and natural gas resources.

Drilling through the cap rock and into the reservoir is used to bring hydrocarbons to the surface. A profitable oil or gas well may be created after the drill bit has reached the reservoir and the hydrocarbons can be brought to the surface by pumping them up to the surface. The well is classed as a dry hole if the drilling effort does not result in the discovery of economically viable amounts of hydrocarbons. A dry hole is normally closed and abandoned.

Methods of Exploration
The presence of visible surface characteristics such as oil seeps, natural gas seeps, and pockmarks (underwater craters formed by escaping gas) serve as the most fundamental evidence of hydrocarbon formation in the environment (be it shallow or deep in the Earth). The majority of exploration, on the other hand, is dependent on very advanced equipment to discover and estimate the extent of these deposits, which is done via the use of exploratory geophysics. Localized gravity surveys, magnetic surveys, passive seismic surveys, and regional seismic reflection surveys are used to discover large-scale characteristics of the sub-surface geology in areas suspected of containing hydrocarbons in the first instance. Features of interest (known as leads) are subjected to more detailed seismic surveys, which are based on the principle of the time it takes for reflected sound waves to travel through matter (rock) of varying densities, and which use the process of depth conversion to create a profile of a substructure’s structure. Finally, when a prospect has been found and analyzed, and if it meets the oil company’s selection criteria, an exploratory well is drilled in an effort to ascertain definitely whether or not there is oil or gas there. The use of electromagnetic technologies may help to lessen the danger of accidents on the ocean floor.

Oil exploration is a costly and high-risk process that requires extensive capital investment. Offshore and remote region exploration are often only performed by major enterprises or national governments with significant financial resources. Deep sea oil wells may cost up to US$100 million or more, whereas shallow shelf oil wells (such as those in the North Sea) can cost as little as US$10 million. The hunt for onshore hydrocarbon reserves is carried out by hundreds of smaller firms throughout the globe, with some wells costing as little as US$100,000.

Aspects of a petroleum exploration potential
A prospect is a prospective trap that geologists feel may contain hydrocarbons and so should be explored. First and foremost, a large amount of geological, structural, and seismic study must be conducted in order to transform the probable hydrocarbon drill site from a lead to an actual prospect. For a prospect to be successful, four geological elements must be present, and if any of these factors are absent, neither oil nor gas will be present.
           - Source rock – When organic-rich rock such as oil shale or coal is subjected to high pressure and temperature over an extended period of time, hydrocarbons form.
           - Migration – The hydrocarbons are expelled from source rock by three density-related mechanisms: the newly matured hydrocarbons are less dense than their precursors, which causes over-pressure; the hydrocarbons are lighter, and so migrate upwards due to buoyancy, and the fluids expand as further burial causes increased heating. Most hydrocarbons migrate to the surface as oil seeps, but some will get trapped.
           - Reservoir – The hydrocarbons are contained in a reservoir rock. This is commonly a porous sandstone or limestone. The oil collects in the pores within the rock although open fractures within non-porous rocks (e.g., fractured granite) may also store hydrocarbons. The reservoir must also be permeable so that the hydrocarbons will flow to surface during production.
           - Trap – The hydrocarbons are buoyant and have to be trapped within a structural (e.g., Anticline, fault block) or stratigraphic trap. The hydrocarbon trap has to be covered by an impermeable rock known as a seal or cap-rock in order to prevent hydrocarbons escaping to the surface

Exploration carries a risk
Because hydrocarbon exploration is a high-risk venture, conducting a thorough risk assessment is essential for effective project portfolio management. It is difficult to quantify exploration risk, but it is often characterized as the degree of trust that can be placed in the existence of the critical geological elements, which were addressed above. Based on data and/or models, this level of confidence is often shown on Common Risk Segment Maps (CRSM) (CRS Maps). High confidence in the existence of critical geological causes is often represented by the color green, whereas low confidence is represented by the color red. The maps are also known as Traffic Light Maps, and the whole method is referred to as Play Fairway Analysis in certain instances (PFA). The purpose of such processes is to compel the geologist to conduct an objective evaluation of all relevant geological parameters. Furthermore, it produces straightforward maps that can be understood by non-geologists and managers, which may be used to inform exploration choices.
https://www.gmsthailand.com/blog/oil-gas-from-start-to-finish/

[ธนัส]

Oil and Gas Production Technology

The burst of production growth in the United States, often known as the “Shale Revolution,” was made possible by the introduction of new technology in the oil and natural gas industries. It was formerly prohibitively costly for oil and gas companies to extract reserves of oil and gas from low-permeability geological formations. However, a combination of horizontal drilling and hydraulic fracturing has made it possible for these deposits to be accessed. Up until quite recently, the United States was the greatest user of oil in the world, accounting for 25 percent of the demand that was met worldwide. New developments in the oil and gas industry in the United States have stimulated economic recovery from the financial crisis that occurred in 2008. This has been accomplished through the creation of new jobs, increased investment in oil- and gas-producing regions, and decreased prices paid by consumers for gasoline. Policymakers are concerned that a significant decrease in the amount of petroleum the United States imports would have geopolitical repercussions that go beyond an improvement in the nation’s energy security and might result in altered diplomatic ties with nations that produce oil. In a similar vein, there is some cause for worry over the possibility for lower export profits for traditional producing nations to both contribute to instability and pose a possible danger to the security interests of the United States. These worries, on the other hand, are unjustified because of a common misunderstanding of the function that oil plays in the process of forming diplomatic connections.

The United States is not the only country in which innovative methods of oil and gas extraction are making their way into use. As a result of price signals, multinational oil firms have begun to explore unconventional hydrocarbon resources in Canada, South America, and Africa. These businesses are looking for larger profits by expanding their operations into new territories. Tar sands drilling and deepwater water drilling are two of the most notable examples of these newly developed production methods. In this part of the article, we will examine the many new kinds of technology for the production of oil and gas that are altering the global energy landscape, as well as the consequences these technologies have for the environment.

The Developmental Process, Broken Down into Its Components
The process of extracting oil and gas may be broken down into four distinct phases:
          - exploration
          - well development
          - production
          - site abandonment

The search for rock formations that are connected with oil or natural gas resources is part of the exploration process, which also includes geophysical prospecting and/or exploratory drilling.

After exploration has located an economically recoverable field, the next step is well development, which involves the construction of one or more wells from the beginning (called spudding) to either abandonment if no hydrocarbons are found in sufficient quantities or to well completion if hydrocarbons are found in sufficient quantities. Well development occurs after exploration has located an economically recoverable field.

The process of production involves the extraction of hydrocarbons, the separation of a combination including liquid hydrocarbons, gas, water, and particles, the elimination of ingredients that are not suitable for sale, and the subsequent sale of liquid hydrocarbons and gas. It is common practice for production sites to process crude oil coming from many wells. Oil is almost usually processed in a refinery; natural gas, on the other hand, may be treated to remove pollutants either in the field or at a natural gas processing plant. Both of these facilities are referred to as natural gas processing plants.

When a freshly drilled well does not have the potential to produce profitable amounts of oil or gas, or when a producing well is no longer economically feasible, site abandonment includes capping the well (or wells) and restoring the site.

Innovative Methods and Equipment for Drilling
Vertical drilling has always been the standard method for oil and gas wells. Operators have been able to save time, cut down on their operating expenses, and have a smaller effect on the environment as a direct result of technological improvements. The following methods are included in the next generation of drilling technologies:

Horizontal Drilling
The drilling process for horizontal wells begins with a vertical well that is then turned horizontal inside the rock of the reservoir in order to provide a larger opening to the reservoir. These horizontal “legs” may be more than a mile in length; the greater the exposure length, the greater the amount of oil and natural gas that can be drained, and the quicker it can flow. Horizontal wells are appealing for a number of reasons: (1) they can be utilized in circumstances in which conventional drilling is either not possible or not cost effective; (2) they reduce surface disturbance because they require fewer wells to reach the reservoir; and (3) horizontal wells can produce anywhere from 15 to 20 times as much oil and gas as a vertical well.

Drilling in Multiple Directions
There are instances when oil and natural gas deposits are situated in distinct strata of the earth’s crust. Drilling in many directions at once gives operators the ability to access deposits located at varying depths. Multilateral drilling is one kind of this drilling. This results in a significant boost in output from a single well while simultaneously lowering the total number of wells that need to be dug on the surface.

Extended Reach Drilling
By using drills with extended reaches, producers are able to access deposits that are located at large distances from the drilling rig. This enables producers to access oil and natural gas resources below the surface of places that are not suitable for drilling vertical wells, such as locations that are not yet developed or areas that are ecologically sensitive. Wells can now extend out over 5 miles from the surface position, and hundreds of wells may be drilled from a single location, decreasing surface effects. Additionally, wells can now reach out over 5 miles from the surface

Drilling on Complicated Routes
When trying to target several accumulations from a single well site, complex well routes might have many twists and turns to attempt to navigate around obstacles. When compared to digging many wells, the use of this technique may be more efficient financially, generate less waste, and have a less impact on the surface.

Advantages of Directional Drilling Technologies (Advanced Drilling Methods)
            - Enhance oil production while simultaneously building up reserves.
            - Natural cracks that intersect one another yet are inaccessible through vertical wells
            - preventing the beginning of gas or water coning, which is a phrase used to describe the process that underlies the upward movement of water and/or the downward movement of gas into the perforations of a producing well, in order to increase the amount of oil that is produced from the well.
            - Increasing output from low-volume or low-pressure reservoirs
            - Improving the “sweep efficiency” of waterflooding, also known as the capacity, to extract more oil from a reservoir after the first extraction, is necessary for reservoirs that are injected with fluids in order to boost oil or gas output.

Unconventional Natural Gas
The conventional oil well is not the only way to extract unconventional oil resources; there are other alternative options. However, the oil sands, tar sands, heavy oil, and oil shale resources mentioned above are not covered by the information provided on this page. Natural gas production using unconventional methods is distinguished by the presence of distinctive geologic characteristics, which increase the difficulty of extracting natural gas from reservoirs. Formations such as tight gas, shale gas, hydrates, and coalbed methane are examples of those that are typically more impermeable or have a lower overall permeability.
https://www.gmsthailand.com/blog/oil-and-gas-production-technology/