Design and operation of unconventional surface facilities process safety tips gas constant for nitrogen


Continuing the August 2018 Tip of the Month (TOTM) [1] on design and operation of unconventional surface facilities, this TOTM presents process safety tips gaslighting for four case studies: 1. Direct Fired Heater Treater Burn Through Failures 2. Tank Blanket Gas / Flame Arrestors 3. Pocketing Vent / Relief Piping 4. Hot Oiling of Oil Storage Tanks to meet TVP / RVP

We start this tip with a quote from a colleague, James A. Britch: “I never regretted buying quality”. There is a lesson in there for unconventional batteries. There is tremendous pressure to reduce capital costs, but you should be focused on life-cycle cost. If you install equipment and then burn down the battery…you haven’t saved much.There’s the loss of capital and revenue from shut-in production.

Direct fired burners are failing due to internal flame impingement directly on the steel, and salt build up on the outside gas bloating back pain of the firetube in the process fluids. The salts build up, act as an insulator, and then steel temperature increases until a burn through occurs. Since the process side of the burner operates at a higher pressure than the natural draft burner, the process fluids enter the burner and ignite. In many instances, this has resulted in massive damage to the grade 9 electricity unit test answers entire battery.

b. Some operators use glycol as a heat transfer fluid. This is a cheaper alternative to expensive heat transfer fluids, but glycols degrade to acetic acid if the skin temperatures of the fire tubes exceed 350 °F (177 °C). These same operators rarely check the pH of their heat transfer fluid until leaks and severe corrosion are found. Heat transfer oils are a better choice.

(2) Direct fired heater with a ceramic sleeve to take the higher temperature shock of direct flame impingement. Heaters normally have ceramic refractory castables and bricks to prevent direct flame impingement. As shown in Figures 2 and 3 Bartz et al. [2] recommends inserting a ceramic tube to spread the heat flux of the flame and avoid burn through.

(3) Best Solution: consider a separate furnace and heat exchanger using heat transfer oils. This solves both issues. The heat transfer oils are designed to operate without degradation at process electricity how it works temperatures required, and the metal temperatures in the heat exchanger will not cause metal failure if there are no salt deposits on the heat exchanger. This may require periodic hydro-blasting, but you electricity word search pdf will not have to rebuild the battery.

Flame arrestors and tank blanket gas provide independent layers of protection between the ignition source – flare or thermal oxidizer – and the vapor space in the water and oil tanks. When evaluating what to use in a design consider using a layer of protection analysis or LOPA [3]. This tool is discussed in the PetroSkills-John M Campbell PS4-Process Safety Course. It provides a semi-quantitative solution to design decisions that are based of failure frequencies and not just personal preferences or gut feels. The more independent layers of protection the lower the frequency of the consequence occurring.

Flame arrestors have a Probability of Failure on Demand (PFD) with a range of 1×10 -1 for arrestors without temperature indicators and an effective isolation / shutdown system, and tank blanket gas (BPCS-Basic Process electricity history timeline Control System) has a PFD of 1×10 -1 [3]. The designer can use both or either to provide independent layers of safety protection. Flame arrestors are subject to plugging from ice, corrosion, fouling, improper or lack of maintenance. Blanket gas works well in this situation due to the narrow range of flammability of methane in the air (5-15% fuel to air). The majority of stock tank incidents occur during maintenance activities with small amounts of gas and large volumes of air.

During the high volume of production timeframe for unconventional tank gas out batteries the stock tanks degas and have “auto-blanketing” of the active tank vapor space. But what happens in the future when rates are very low? What happens in water tanks that are not provided with gas blanketing? This also explains why water production tanks / injection batteries experience tank fires/explosions. In general, methane has a very low solubility in water – approximately 2 SCF/STB (0.36 Sm 3/STm 3) of water going from 250 psi (1724 gas exchange in the lungs kPa ) to atmospheric pressure. This small volume often results in flammable mixtures in the vapor space of the tank.

Many unconventional tank batteries run their vent / flare / thermal oxidizer piping at grade on sleepers with zero slope , then jump vertically into a flare knockout (see Figure 5). This pocketed piping is a liquid trap for water and heavier hydrocarbons. Once a liquid pocket forms, the tanks overpressure gas and supply shreveport, and then vent locally through their pressure/vacuum reliefs and thief hatches. In the winter this pocket can freeze and block the flare (see Figure 6). This can also cause a loss of containment when a PSV activates and cannot depressure to the flare. This causes a loss of revenue, as well as an environmental and safety issue. These vapors are extremely rich and normally are much heavier than air. This creates the potential for an unconfined vapor cloud explosion or flash fire locally.

These issues electricity 101 pdf causing tanks to vent heavier than air molecules (propane/butane) can lead to flash fires and unconfined vapor cloud explosions (UCVE). Heavy vapor generally finds an ignition source. Figure 8 shows how oxygen may get into the oil stock tanks. Getting oxygen into your system causes major damage to the gas plant amine systems, and TEG systems, as well as general corrosion in your facilities.

As illustrated in Figure 9, some operators use hot oil trucks during winter months to heat the crude oil in the tanks to flash light ends off the crude to meet vapor pressure specifications for crude sales. The solution to this issue electricity and circuits test is not to use hot oil trucks but is to stabilize the crude or use a design using Vapor Recovery Towers (VRT) as discussed in the August 2018 Tip of the Month- Design and Operation of Unconventional Surface Facilities Issues-Stabilization [1].

The hot oil truck is a direct fired (propane) heater with propane storage, and diesel or oil storage. It is normally used to pump hot oil at high pressure down the well’s tubing to melt wax deposits. This operation is normally done for 24 hrs/day during winter months to stabilize the crude bp gas prices ny. It is extremely dangerous, and many flash fires have occurred in the past few years.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G4 (Gas Conditioning and Processing), PF3 (Concept Selection and Specification of Production Facilities in Field Development Projects), PF4 (Oil Production and Processing Facilities), PF49 (Troubleshooting Oil Gas Processing Facilities), and PS4 (Process Safety Engineering)courses.

Mr. James Langer is a registered professional chemical engineer in Texas and California. He graduated with a BS in Chemical Engineering from UCLA and has an MBA from Pepperdine. Jim has been working for Hess as a Senior Process Engineering Advisor electricity invented or discovered for the past 7 years. He is retired from Shell having worked 28 years as a Senior Staff Process Engineer, and Principal Technical Expert for Shell / Shell Global Solutions. He has had a global job for the past 15 years and had experience in offshore / onshore, shallow water / deep water, heavy oil / light oil, water treating, and natural gas processing. He has been a project manager working electricity facts for 4th graders field development projects through all of the phase gates and stages. He frequently travels the globe assisting operations with process issues, and showing them how to unlock additional barrels through the application of production optimization. Jim installed Shell’s smallest, most expensive gas plant. The project took 8 years and is located on Pacific Coast Highway in Huntington Beach California.