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Home > About KOC > KOC Operations > Production > Gas Operation Facilities > Functions of Booster Stations
Functions of Booster Stations
A Booster Station is part of an oilfield facility installed to fully utilize the separated gas from the Gathering Centers which was previously wasted to flare. Typically, a Booster Station has the following functions:
Receives the gas from various Gathering Centers and compresses it.
Separates the condensate from the gas stream.
Dehydrates (removes water) from both compressed gas and condensate.
Receives and dehydrates condensates from the Gathering Centers.
The compressed gas and condensate are transmitted separately through pipelines to Mina AlAhmadi LPG PLant, where the transmitted gas and liquid is processed to recover Gasoline and Liquefied Petroleum Gases (LPG) and exported.
After Processing at the LPG Plant, effluent gas (known as lean gas) is distributed as fuel gas to industrial users in Kuwait (ie. Power Stations and Refineries) and the excess is utilized for fueling the oilfields GCs and/or flared in dedicated excess flares. Booster Station Process Flow Scheme
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Home > About KOC > KOC Operations > Production > Gas Operation Facilities > Main Components of Gas Booster Station
Compression Units | Condensate Make and Pumping | Gas Dehydration | Liquid Dehydration
Main Components of Gas Booster Station
Compression Units Condensate Make and Pumping Gas Dehydration Liquid Dehydration
Compression Units Top
Each Booster Station compression unit is made up of two or more compression trains, the following is a brief description of one of the trains.
The low pressure gas collected from the various Gathering Centers is transmitted to the Booster Station where it is pressure regulated and routed to a suction scrubber (C-101). Here the free liquid present (basically water) is scrubbed out of the gas stream and dumped. The gas is then compressed by the Low Pressure gas compressor, cooled by aerial coolers “Fin-Fans” (E-101) and then routed to the second stage. The second stage suction scrubber (C-102) receives the LP compressor discharge gas as well as high pressure gas from Gathering Center HP Network, at this stage, any condensate being formed are pumped to the high pressure compressor discharge vessel (C-103). The gas is compressed by the high pressure compressor, cooled by aerial coolers (E-102) and routed to the high pressure compressor discharge vessel (C-103), where more condensate are formed.
The LP and HP Compression Units consist of centrifugal gas compressor sets driven by heavy duty Gas Turbines.
Condensate Make and Pumping Top
In addition to the condensates being formed within the Booster Station, the condensate from some GCs is diverted through the Booster Station and connected to the high pressure discharge vessel (C-103).
The condensate collected from the high pressure compressor discharge vessel (C-103) are pumped through the condensate dehydrators and separate pipelines to Mina Al-Ahmadi LPG Plant. In most areas, the condensate is dried to a Dewpoint of 50 ppm (Wt. Vol.) to prevent corrosion to the transmission pipelines. In West Kuwait, where the gas is sour (containing high level of H2S), the water in condensate is removed to a much lower level ie. 40 ppm (Wt. Vol.)
Gas Dehydration Top
The gas from the high pressure discharge vessel (C-103) is routed to the gas dehydration unit where water is removed from the gas in the absorber tower. The gas is directed upward through the tower and Tri-ethylene Glycol (TEG) flows downward and absorbs water vapor. Here the Glycol is enriched with water and settles at the bottom hold-up where it is discharged from the tower through a level control valve and sent to the glycol regeneration unit. The regeneration unit removes water vapor and gas that are mixed with the glycol. The glycol is then recirculated to the absorber for further gas dehydration. the gas product in the absorber is scrubbed by a wire mesh (demister) to remove any glycol droplets that are carried over with the gas. The dry gas is then sent to the LPG Gas Plant via separate pipeline.
At BS-130/140/150 the gas is dried to a water dewpoint at 60°F while at BS-170 it is dried further down to 40°F DP. BS-170 gas is depressed to 40°F DP due to sourness (H2S content) of the gas.
Liquid Dehydration
Top
Liquid dehydration plant dries (removes water) from the condensate to a point where it will not cause corrosion to the liquid pipeline going to the LPG Plant. In all stations the water in condensate is removed to a water content of 50 ppm (Wt. Vol.).
The liquid dehydration plant consists of the following:
Basket Strainer
To remove line trash, sand and other solid particles large enough to cause damage to rotating equipment, valves, etc
Coalescer Filter
To remove free water from the condensate.
Charcol Filter
To remove any carry-over of heavy oils (like lube/seal oils) in the condensate.
Adsorber
A vessel filled with a drying material known as “molecular sieve” which dries out most of the dissolved water from the condensate
As the adsorbing material become saturated with water, the liquid is switched to a parallel “standby” vessel/dryer. The saturated molecular sieves of the previous dryer gets “regenerated” and placed on stand-by, ready for another cycle.
The regeneration cycle consists of two major steps ie., Heating and Cooling. Heating is done by circulating hot gas at a temperature of 550°F through the Dryer while Cooling is accomplished by circulating cool dry product (condensate) through the dryer. The heating cycle ends when the regeneration gas flow temperature from the dryer reaches a preset level (ie. 450°F). And the cooling cycle ends when the dryer also reaches the preset level (ie. 150°F).
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The TRACE MODE SCADA/HMI Based Control System of Oil Booster Pump Station at Surgutneft (Western Siberia)
Surgutneft (a branch of Surgutneftegaz oil company) is the oldest oil and gas extraction company in Western Siberia (Surgut City, Russia). The company has recently celebrated its 40th anniversary. In 2003, at the booster pump station 1 of the Piltanskoye oil field, during a planned reconstruction a new TRACE MODE SCADA/HMI based control system was successfully implemented.
By the day of the new booster pump station commissioning , not only controllers and servers but also all remaining control equipment, including gauges, actuators and data transmission lines were renewed. Therefore, by the moment of the control system setup, the builder staff were still working at the control room where operator HMI workstations and cabinets with field devices would have to be installed. The electric wiring had not been even laid to the these cabinets. And, nevertheless, engineers of the АТ Company (Moscow, Russia), AdAstrA’s authorized system integrator, with assistance of the Surgutneft control and instrumentation service within the shortest time, have set up the control system and launched it in the trial operation mode. The successful implementation would undoubtedly be impossible without an optimal selection of basic software: SCADA/HMI system TRACE MODE by AdAstrA Research Group.
The Surgutneft oil and gas extraction department has chosen for the booster pump station-1 the М2000 PLCs connected through the RS-485 interface. The 8 PID-loops implemented in the M2000 carry out the following controls:
maintaining of the specified level of liquid in the S-1/1 and S-1/2 separators using controllable pneumatic outlet valves; maintaining of the specified liquid level in the S-2/1 and S-2/2 separators using frequency converters controlling the pump capacity; maintaining of the specified pressure in the G1 gas separator; maintaining of the specified inlet pressure for the G3 gas separator; maintaining of the specified gas outlet pressure for the Heater-Treater installation; maintaining of the specified pressure at the separation stage 2 (S-2/1, S-2/2); maintaining of the specified gas pressure at the molecular gate valve.
Besides the PID control, other control technologies are also used in the Surgutneft oil and gas extraction department’s booster pump station 1 control system: digital regulator of the liquid level in draining vessels; semiautomatic control of condensate discharge from hot wells; manual control of electrical gate valves; manual control of pumps.
In addition, М2000 controllers carry out the acquisition of data from pressure, temperature and current gauges. Via one of the controllers (master in the RS-485 network), data are supplied, via the RS-232 interface, to the computer, on which the SCADA server, i.e.the TRACE MODE Real Time Monitor, is installed, providing HMI features. The main HMI screen is a simplified mnemonic diagram including all basic booster pump station units.
On the main screen, the operator can view real values of basic process parameters, change the regulator setpoints and monitor the PID-loop operation. If necessary, the operator can switch off the automatic control and change over to the manual actuator control mode. The developers of the booster pump station-1 control system main screen solved a hard ergonomic problem how to display all necessary process information and at the same time not to overload the screen by excessive interface elements. In order to solve this problem, the TRACE MODE graphical objects
visibility control feature has been used, by means of which the PID-loop settings and the condensate discharge control have been arranged as pop-up windows. Apart from regulation parameters, the indication of the following idexes has been arranged on the booster pump station-1 MPCS main screen: booster pump station inlet liquid pressure; booster pump station outlet oil pressure and temperature; oil pump outlet pressure; liquid level in the G1 gas separator, R1, RO-1, RO-2, RV1, RV2 reservoirs and drainage tanks; limiting liquid levels in the separation reservoirs of Stages I and II, G1, G2, G3 gas separators, K2 hot well, R1, RO-1, RO-2, RV1, RV2 reservoirs and drainage tanks; limiting pressure values in the separation Stage II, G1, G2, G3 gas separators; gas content gauges in the oil pump and reagent service unit rooms and a number of auxiliary signals.
All analog signals are provided with individual break indicators. That enables the booster pump station operators to monitor system operability visually.
In order to display charts - the historic trends of pressure and liquid level - the system was provided with a separate screen - to which a convenient navigation was arranged by means of a key panel in the bottom screen area. In order to adjust PID-loops and conduct routine maintenance and repairs, special screens have been developed for each М2000 controller. Separate screens have also been allocated for alarm reports, pump control and gate valve control. A sound alarm signalling with acknowledgement has been arranged for emergency digital signals. A siren sound was used alarms.
Upon expiration of two weeks of arduous labour, the system was commissioned for pilot commercial operation.
The next stage of setup works included automation of the group pump station. This meant connection of the Gamma-7 level measuring controllers as well as addition of a number of digital
and analog gauges to the operating booster pump station control system. At the second stage, main difficulties were caused by the works at the “living” device with round-the-clock operation; therefore, the setup work were finished after two weeks. It should be noted that controllers by different manufacturers (М2000, Gamma-7) have been integrated into the system but it did not cause any difficulties as all necessary drivers were supplied free of charge with the SCADA/HMI system TRACE MODE .
Totally, about 650 TRACE MODE channels (tags) were used in the Surgutneft’s booster pump station-1 control system. The development and the setup of the project software have taken 2 man-months. The control system maintenance is carried out by the Surgutneft oil and gas extraction department’s control engineering service, one engineer permanently works at the booster pump station, which responsibilities include maintenance of both the control system software and hardware.
Afterwards the TRACE MODE SCADA/HMI based control system was successfully integrated into a Surgutneftegaz OJSC’s corporate informational system. The use of TRACE MODE SCADA/HMI has shown the advantages of this software. The users pointed out the ease of modifications of the system, for example, when a new gauge was added. The maintenance of the TRACE MODE SCADA/HMI based control system is significantly cheaper because it does not require inspections of the control engineers from the head department – all necessary add-on’s may be done by the local staff.
Aktualna wersja TRACE MODE 6.07.
NEWS 28.09.2010 SCADA TRACE MODE steruje linią do produkcji wyrobów torfowych 02.06.2009
SCADA TRACE MODE wykorzystana do sterowania procesami przetwarzania łupka naftowego w największej europejskiej firmie działającej w tej branży 04.10.2007 Intel wykorzystał TRACE MODE SCADA/HMI do sterowania automatyką budynku biurowego 29.12.2006 SCADA TRACE MODE 6 w systemie sterowania europejskiej elektrowni atomowej
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How Do Pumping Stations Work?
In the US alone, there are thousands of miles of pipelines carrying crude oil and other petroleum products to destinations throughout the 48 mainland states. While the product begins its journey with major force, the product loses forward momentum over time and distance.
To overcome this, pumping stations are positioned throughout the length of the pipeline to adjust the pressure, pump the product along the line and monitor flow and other information about the transmittal of the product. (In pipeline systems carrying natural gas, similar stations are located throughout the line to help push the product along, but they are called compressor stations.)
Pipeline pumping stations also increase the through-put of the pipeline. In other words, if a pipeline needs to be able to have a higher through-put capacity, another pipeline pumping station may be added to overcome the challenge.
Pipeline pumping stations may be strategically located for their proximity to other equipment, or a pumping station may be constructed to help push the product through a more difficult section of the pipeline, such as over a mountain range.
There are a number of different types of pumps that can be found in the pumping stations, including a full head pump, which is a two-stage pump with the impellers in a series, consisting of one inlet and one outlet. Also, there are half stage pumps with the impellers in parallel and including two inlets and two outlets. Half stage pumps are capable of handling twice the flow of full head pumps, but only produce half the pressure rise. Pumping stations may also house booster pumps, which move product from the storage tanks at the station into the main line.
Pumping stations also contain safety equipment and house on-staff safety personnel to overcome any problems along the pipeline route. Additionally, pumping stations are often the location for launching pipeline pigs to help clear the line and inspect the pipeline for any corrosion or other damage from the inside.
Pumping Stations at Work: Trans-Alaska Pipeline
Traveling a distance of more than 800 miles, the Trans-Alaska pipeline transports oil produced on the North Slope's Prudhoe Bay to the Port of Valdez in southern Alaska for shipment via tankers to US markets.
Trans-Alaska Pipeline
Source: University of Minnesota Duluth
This massive pipeline boasts 11 pumping stations, although the line was designed to house 12. Coming online in 1977, the pipeline first had eight pumping stations working, which picked up to 11 by 1980 as through-put ramped up. After daily capacity has dropped over time, the pipeline now has five operating stations with one reserve station.
Pumping Station 1 has a pumping capacity of 420,000 barrels of oil per day, and Pumping Station 5 has a through-put capacity of 150,000 barrels of oil per day. All the other stations house a pumping capacity of 55,000 barrels of oil per day.
At each pumping station, there are anywhere from 10 to 25 personnel that work there, and these employees work 12-hour days in either a one week on, one week off shift or a two weeks on, two weeks off shift. More Pipelines Articles•
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More Courses Crude Oil Pipeline Control Is It Possible to Maintain an Accurate and Stable Pressure Control Just Using Speed Control?
09/27/2012 1 vote Share Print Related RSS Page 1 of 2 « Prev 1 | 2 Next » View on one page
This column is moderated by Béla Lipták, automation and safety consultant, former Chief Instrument Engineer of C&R and former Yale professor of process control, who is also the editor of the Instrument Engineer’s Handbook (IEH). If you would like to become a contributor, visit Contributors Wanted. Q: We are happy users of your invaluable series of handbooks for instrumentation and process control. There is something we could not find in Vol. 2, Chapter 8.34, about control of pumps. What would be your recommendation for the control of two pairs of reciprocating pumps installed in series (booster/main arrangement pump) used in a crude oil pumping station? As shown in the image below and in the attached PFD you will be able to understand better the addressed control problem.
The pumping station delivers crude oil to the pipe line, and has two pumping stages, booster and main (each one in a redundant configuration—two operative and one cold standby—with a total capacity of 300 KBPD). All pumps (both boosters and mains) are of the positive displacement type. The boosters are 1200 hp and the mains are 3000 hp each. Each pump has its own hydrodynamic speed driver for velocity control whose setpoint is provided by a selector control between the total flow and the discharge pressure for the booster pumps. For the main pumps, the selector is between the total flow, the suction pressure and the discharge pressure, and, therefore, the
controller with the lowest demand will set the velocity to the respective pump. Our questions are as follows: For a pumping configuration with reciprocating pumps in series, each one with its own speed control, is it possible to maintain an accurate and stable pressure control just using speed control? If a booster pump or a main pump shuts down, would this control system be able to respond in time in order to maintain pressure balance on the system? Someone suggested to us to include a control pressure valve to recirculate oil at the intermediate manifold between boosting stage and main stage, which will fast-actuate in order to stabilize the pressure if needed. Would this work?
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We appreciate your suggestions and critique. There is too much debate here at my company about this point.
Luis Fernando Betancur
[email protected]
A: You are right, Chapter 8.34 in Vol. 2 does not answer all your questins, you also have to read Chapters 7.4 and 8.35 to get the full picture.
Your solution of using variable-speed (VS) positive displacement (PD) pumps, instead of throttling bypass control valves, is the correct one, because the pipeline process is a mostly friction one, and you would be wasting a lot of energy in the form of valve pressure drops. With PD pumps, cavitation also is less of a problem.
As to installing a recirculating control valve back to the supply tank from the intermediate manifold, this is reasonable if you want to mix the tank contents before start-up (to reduce settling and achieve uniform density) or to gradually increase the booster discharge pressure during startup to the required inlet pressure of the main pumps before they are started, but not for normal operation. The relief valves should take care of overpressures. You need those plus blocks and check valves on each pump. In addition to the pressure safety valve (PSV) opening in the bypass, the booster pumps have to shut down any time the main pump trips, and, similarly, the main pumps have to trip to prevent the development of low suction pressure, when the boosters trip.
I assume you have selected the booster pumps that require a minimum inlet pressure (net positive suction head required, NPSHR) that is lower than the net positive suction head available (NPSHA). To determine this minimum, you determine NPSHA using the minimum possible supply tank level and oil density in combination with the maximum oil density expected.
The purpose of the booster pump is to keep the main pump suction pressure constant by compensating for supply tank level, viscosity, etc. If we understand "the personality"of the pipeline process, the required controls become fairly obvious. As you can see in Part A of Figure 1, the pump curves (in red) of all VS-PD pumps are very steep parallel lines, because flow changes very little, even with large changes in discharge pressure. If you have a pair of pumps in parallel, pump flows are added (Part B), and if you have a pair of pumps in series, pump pressure is added (ΔPs are added in Part C). In your case, you have both series and parallel operations (Part D), so the combined pump curves are as shown by the parallel red lines. For sake of this illustration, I have assumed that all pumps are the same (which obviously is not the case), but it simplifies the explanation.
Pumps in tandem Figure 1. The pump curves (red) of various combinations of positive displacement pumps are displayed on plots where the abscissa is flow in % of the maximum capacity of one pump, and the ordinate is pressure in % of the maximum discharge pressure of one pump. Blue is the system curve (pressure-flow relationship) of the pumping station, and where the blue and red lines cross is the operating point. Once we control one of the variables (flow or pressure), the other one is fixed.
Because your process is a "mostly friction" one, with only a small elevation ("static head") component, your system curve is basically a parabola (blue in Part D). If you select an operating point on Part D by controlling the discharge pressure (or flow) at a particular value, you have, in effect, also set the other. For example, in the sketch, I have picked a flow controller (FIC) setpoint which equals 120% of the full capacity of one pump. This automatically sets the discharge pressure also P3 = 50% of one pump) and the speed at 63%.
Obviously, in your actual configuration the four pumps are not the same, (the main pumps are nearly three times as powerful as the boosters) and, consequently, the combined pump curves will be different from the ones I have shown in Part D, but the concept is the same.
Now, let me turn to the control of the the pumping station. If you want only stable operation, you can modulate the speed of the booster stage to maintain the suction pressure for the main stage, and can throttle the speed of the main stage to keep the discharge (flow or pressure) constant. This, with safety limits and start-up/shutdown logic is all you need.
What I will describe below is the system you should consider if you want to maximize the efficiency (minimize the energy consumption) of the pumping station. To do that, we have to understand that this process has four degrees of freedom (total load, boost/main load ratio, and load distribution in both pairs of pumps) and, therefore, we can place four controllers on it without causing excessive interaction ("fighting") among them. Also, because the oil is incompressible, the loops are fast, so I usually tune these loops for mostly integral behavior (very little proportional gain).
The first loop controls the discharge pressure of the main stage. I usually use a "neutral gap" PIC, so that the controller output remains unchanged as long as the pressure is within ±1% of setpoint. This stabilizes the loop, which has fast measurements, but relatively slow speed controller response, and is, therefore, noisy or interacts with other loops.
The second loop controls the load distribution between the boost and main stages (booster % = (P2-P1)/(P3-P1)) to guaranty maximum station efficiency. This interstage (booster discharge) pressure controller compares the above optimum desired setpoint with the actual value of (P2P1)/(P3-P1), and adjusts the load on the booster stage until it is optimum. Naturally, this PIC setpoint is limited (high selector), so that it can not drop below the minimum suction pressure requirement of the main stage.
Similarly, we can optimize the other two loops by optimizing the distribution of the flows among the two pumps within each stage. This is accomplished by measuring the individual flows, and because we know the optimum flow distribution (optimum setpoint = F1/(F1 + F2), we can modulate the speeds to achieve that. In this configuration, the output of the stage pressure controller becomes the cascade master of the more efficient pump's flow controller, while the less efficient meets the remaining load.
To implement his type of optimized control system, the pump supplier has to provide reliable efficiency data for the pumps. If they can't do that, or if the unique piping configuration of the particular pumping station is to be also considered, efficiency data can be accumulated on the basis of past operating performance. This is done by comparing the kWs that were needed to deliver the same flows at the same ΔP at different pump loading combinations in the past, and selecting the least energy-demanding one. This strategy can also be used to signal the need for "pigging" (cleaning) the pipeline if the pumping power required to deliver the same load rises.
Such an optimizated variable-speed pumping station can reduce the energy cost of operation to one half of a constant- speed pumping station using control valves.
Béla Lipták
[email protected]
A: This is fundamental cascade control. Control of the booster pump is the inner loop, compensating for such things as tank level, suction pressure, etc. The goal of the booster pump is to provide a constant input to the main pump.
Victor Wegelin
[email protected]
A: The issue of pump control has several aspects that require analysis.
Is the booster pump receiving from an extremely low head pressure and raising the outlet pressure so that the main pump can supply the outlet pressure within the correct pump curve? Will the booster pump be in line with one or several main pumps, such that the booster pump(s) can deliver the required flow and pressure to the main pump(s)? If the booster is not dedicated to one single main pump, but rather to several, it may need the analysis of how many booster pumps you need to have. Since the premise is that the pumps are reciprocating, which means that the speed control and response time of the pumps are not instantaneous, the time delay of operating the booster and main pumps has to be linked based on time delays, as well as production needs.
Based on the basics defined before, we would be able to define the control requires as follows:
Assuming that the booster is dedicated to one main pump, the most effective method is that the speed of the motors be regulated and have dedicated bypass valves to avoid cavitation surges and overpressuring the system.
The operation would consist of starting up the booster and having it recirculate the flow (to avoid overheating the pump) through the bypass valve. Once the pressure is at the minimum operating head pressure of the main pump, then start this pump and recirculate the flow while the outlet pressure builds close to the line operating pressure.
You can operate the system with two individual pressure control loops, or you can have a cascade loop with a master and slave controller arrangement. The main issue is to define the actual time delay of pump responses and ramp-up speeds (to avoid the surges and cavitation). Obviously the final arrangement will depend on the detailed configuration of the system.
The basic control scheme is presented below.
It must be noted that for clarity's sake all the pressure gauges, switches, flow elements, etc., are not shown—just the basic concept of an option to control the pump arrangement.
This system allows the ramp-up of speed and control of the recirculation, minimizing cavitation, surges or overpressuring the system.
If there are several booster(s) that feed several main line pumps, the basic control would need to include flow measurement for better distribution and probably ratio control for the dosification of the pressures and flows to minimize upsets.
To best develop the required control scheme, more detailed information is required. This is only a basic scheme.
Alejandro Varga
[email protected]
A: Unlike centrifugal pumps, the torque requirements of PD pumps are directly related to the DP across the pumps and independent of speed. Hence, a pressure-based speed control will accurately maintain stable flow across the pumps with good turn down as long as you maintain net positive inlet pressure (NPIP) requirements of both the pumps (minimum pressure limit based on current process fluid density in your control loops).
Since PD pumps cannot run on shut head, you need to shut off booster pumps any time the main pump trips along with a PSV in the booster bypass loop. Similarly the main pump will trip on NPIP protection when the booster trips.
A bypass control valve on booster pump is used when speed control is not implemented due to cost or pump design or electrical supply system harmonics limitations.
L. Rajagopalan
[email protected]
A: Rules of thumb for series pump start-up/control are mentioned below.
NPSH is maintained prior to start of the second pumps. Second pump will not run dry. Capacity of both pumps will be adjusted and similar, unless second pump operates on the pressure controlled manifold. Pressure control valve on the discharge line.
Debasis Guha
[email protected]
A: Assuming that crude oil is incompressible, a buffer tank will be required between the pumps to absorb the variations as the pistons reciprocate. The first pump should be controlled by the level in the tank. The second pump should be controlled by whatever it pumps into. But I am a simple mechanical engineer with no experience in crude things, and I can't afford a copy of the IEH.
Bill Hawkins
[email protected]
A: I have never set up such a system, but have a couple comments. First, it might be interesting to measure the constant-speed case total recirculation flow to enable some efficiency optimization, similar to the variable-speed case. Second, I like the variable-speed method too, but wonder if the cost (vs fixed speed) would be justifiable at the large HP mentioned. Separator (oil production) From Wikipedia, the free encyclopedia Jump to: navigation, search
The term separator in oilfield terminology designates a pressure vessel used for separating well fluids produced from oil and gas wells into gaseous and liquid components. A separator for
petroleum production is a large vessel designed to separate production fluids into their constituent components of oil, gas and water. A separating vessel may be referred to in the following ways: Oil and gas separator, Separator, Stage separator, Trap, Knockout vessel (Knockout drum, knockout trap, water knockout, or liquid knockout), Flash chamber (flash vessel or flash trap), Expansion separator or expansion vessel, Scrubber (gas scrubber), Filter (gas filter). These separating vessels are normally used on a producing lease or platform near the wellhead, manifold, or tank battery to separate fluids produced from oil and gas wells into oil and gas or liquid and gas. An oil and gas separator generally includes the following essential components and features:
1. A vessel that includes (a) primary separation device and/or section, (b) secondary “gravity” settling (separating) section, (c) mist extractor to remove small liquid particles from the gas, (d) gas outlet, (e) liquid settling (separating) section to remove gas or vapor from oil (on a three-phase unit, this section also separates water from oil), (f) oil outlet, and (g) water outlet (three-phase unit).
2. Adequate volumetric liquid capacity to handle liquid surges (slugs) from the wells and/or flowlines.
3. Adequate vessel diameter and height or length to allow most of the liquid to separate from the gas so that the mist extractor will not be flooded.
4. A means of controlling an oil level in the separator, which usually includes a liquid-level controller and a diaphragm motor valve on the gas outlet.
5. A backpressure valve on the gas outlet to maintain a steady pressure in the vessel.
6. Pressure relief devices.
Separators work on the principle that the three components have different densities, which allows them to stratify when moving slowly with gas on top, water on the bottom and oil in the middle. Any solids such as sand will also settle in the bottom of the separator. The functions of oil and gas
separators can be divided into the primary and secondary functions which will be discussed later on.Contents [hide] 1 Classification of Oil and Gas Separators 1.1 Classification by Operating Configuration 1.2 Classification by Function 1.3 Classification by Operating Pressure 1.4 Classification by Application 2 Primary Functions of Oil and Gas Separators 2.1 Removal of Oil From Gas 2.2 Removal of Gas From Oil 2.3 Separation of Water From Oil 3 Secondary Functions of Oil and Gas Separators 3.1 Maintenance of Optimum Pressure on Separator 3.2 Maintenance of Liquid Seal in Separator 4 Methods Used To Remove Oil From Gas in Separators 4.1 Density Difference (Gravity Separation) 4.2 Impingement 4.3 Change of Flow Direction 4.4 Change of Flow Velocity 4.5 Centrifugal Force 5 Methods Used To Remove Gas From Oil in Separators 5.1 Settling 5.2 Agitation 5.3 Heat 5.4 Centrifugal Force 6 Flow Measurements in Oil and Gas Separators
7 Flow Calibration in Oil and Gas Separators 8 Controls, Valves, Accessories, and Safety Features for Oil and Gas Separators 8.1 Controls 8.2 Valves 8.3 Accessories 8.4 Safety Features for Oil and Gas Separators 9 Operation and Maintenance Considerations for Oil and Gas Separators 9.1 Periodic Inspection 9.2 Installation of Safety Devices 9.3 Low Temperature 9.4 Corrosive Fluids 10 See also 11 External links 12 References
[edit] Classification of Oil and Gas Separators [edit] Classification by Operating Configuration
Oil and gas separators can have three general configurations: vertical, horizontal, and spherical. Vertical separators can vary in size from 10 or 12 in. in diameter and 4 to 5 ft seam to seam (S to S) up to 10 or 12 ft in diameter and 15 to 25 ft S to S. Horizontal separators may vary in size from 10 or 12 in. in diameter and 4 to 5 ft S to S up to 15 to 16 ft in diameter and 60 to 70 ft S to S. Spherical separators are usually available in 24 or 30 in. up to 66 to 72 in. in diameter. Horizontal oil and gas separators are manufactured with monotube and dual-tube shells. Monotube units have one cylindrical shell, and dual-tube units have two cylindrical parallel shells with one above the other. Both types of units can be used for two-phase and three-phase service. A monotube horizontal oil and gas separator is usually preferred over a dual-tube unit. The monotube unit has
greater area for gas flow as well as a greater oil/gas interface area than is usually available in a dual-tube separator of comparable price. The monotube separator will usually afford a longer retention time because the larger single-tube vessel retains a larger volume of oil than the dualtube separator. It is also easier to clean than the dualtube unit. In cold climates, freezing will likely cause less trouble in the monotube unit because the liquid is usually in close contact with the warm stream of gas flowing through the separator. The monotube design normally has a lower silhouette than the dual-tube unit, and it is easier to stack them for multiple-stage separation on offshore platforms where space is limited. It was illustrated by Powers et al (1990)[1] that vertical separators should be constructed such that the flow stream enters near the top and passes through a gas/liquid separating chamber even though they are not competitive alternatives unlike the horizontal separators. [edit] Classification by Function
The three configurations of separators are available for two-phase operation and three-phase operation. In the two-phase units, gas is separated from the liquid with the gas and liquid being discharged separately. Oil and gas separators are mechanically designed such that the liquid and gas components are separated from the hydrocarbon steam at specific temperature and pressure according to Arnold et al (2008).[2] In three-phase separators, well fluid is separated into gas, oil, and water with the three fluids being discharged separately. The gas-liquid separation section of the separator is determined by the maximum removal droplet size using the Souders–Brown equation with an appropriate K factor. The oil-water separation section is held for a retention time that is provided by laboratory test data, pilot plant operating procedure, or operating experience. In the case where the retention time is not available, the recommended retention time for three phase separator in API 12J is used. The sizing methods by K factor and retention time give proper separator sizes. According to Song et al (2010),[3] engineers sometimes need further information for the design conditions of downstream equipment, i.e., liquid loading for the mist extractor, water content for the crude dehydrator/desalter or oil content for the water treatment. [edit] Classification by Operating Pressure
Oil and gas separators can operate at pressures ranging from a high vacuum to 4,000 to 5,000 psi. Most oil and gas separators operate in the pressure range of 20 to 1,500 psi.Separators may be referred to as low pressure, medium pressure, or high pressure. Low-pressure separators usually operate at pressures ranging from 10 to 20 up to 180 to 225 psi. Medium-pressure separators usually operate at pressures ranging from 230 to 250 up to 600 to 700 psi. High-pressure separators generally operate in the wide pressure range from 750 to 1,500 psi.
[edit] Classification by Application
Oil and gas separators may be classified according to application as test separator, production separator, low temperature separator, metering separator, elevated separator, and stage separators (first stage, second stage, etc.). Test Separator:
A test separator is used to separate and to meter the well fluids. The test separator can be referred to as a well tester or well checker. Test separators can be vertical, horizontal, or spherical. They can be two-phase or three-phase. They can be permanently installed or portable (skid or trailer mounted). Test separators can be equipped with various types of meters for measuring the oil, gas, and/or water for potential tests, periodic production tests, marginal well tests, etc. Production Separator:
A production separator is used to separate the produced well fluid from a well, group of wells, or a lease on a daily or continuous basis. Production separators can be vertical, horizontal, or spherical. They can be two phase or three phase. Production separators range in size from 12 in. to 15 ft in diameter, with most units ranging from 30 in. to 10 ft in diameter. They range in length from 6 to 70 ft, with most from 10 to 40 ft long. Low-Temperature Separator:
A low-temperature separator is a special one in which high-pressure well fluid is jetted into the vessel through a choke or pressure reducing valve so that the separator temperature is reduced appreciably below the well-fluid temperature. The temperature reduction is obtained by the JouleThomson effect of expanding well fluid as it flows through the pressure-reducing choke or valve into the separator. The lower operating temperature in the separator causes condensation of vapors that otherwise would exit the separator in the vapor state. Liquids thus recovered require stabilization to prevent excessive evaporation in the storage tanks. Metering Separator:
The function of separating well fluids into oil, gas, and water and metering the liquids can be accomplished in one vessel. These vessels are commonly referred to as metering separators and are available for two-phase and three-phase operation. These units are available in special models that make them suitable for accurately metering foaming and heavy viscous oil. [edit] Primary Functions of Oil and Gas Separators
Separation of oil from gas may begin as the fluid flows through the producing formation into the well bore and may progressively increase through the tubing, flow lines, and surface handling equipment. Under certain conditions, the fluid may be completely separated into liquid and gas before it reaches the oil and gas separator. In such cases, the separator vessel affords only an “enlargement” to permit gas to ascend to one outlet and liquid to descend to another. [edit] Removal of Oil From Gas
Difference in density of the liquid and gaseous hydrocarbons may accomplish acceptable separation in an oil and gas separator. However, in some instances, it is necessary to use mechanical devices commonly referred to as “mist extractors” to remove liquid mist from the gas before it is discharged from the separator. Also, it may be desirable or necessary to use some means to remove nonsolution gas from the oil before the oil is discharged from the separator. [edit] Removal of Gas From Oil
The physical and chemical characteristics of the oil and its conditions of pressure and temperature determine the amount of gas it will contain in solution. The rate at which the gas is liberated from a given oil is a function of change in pressure and temperature. The volume of gas that an oil and gas separator will remove from crude oil is dependent on (1) physical and chemical characteristics of the crude, (2) operating pressure, (3) operating temperature, (4) rate of throughput, (5) size and configuration of the separator, and (6) other factors.
Agitation, heat, special baffling, coalescing packs, and filtering materials can assist in the removal of nonsolution gas that otherwise may be retained in the oil because of the viscosity and surface tension of the oil. Gas can be removed from the top of the drum by virtue of being gas. Oil and
water are separated by a baffle at the end of the separator, which is set at a height close to the oilwater contact, allowing oil to spill over onto the other side, while trapping water on the near side. The two fluids can then be piped out of the separator from their respective sides of the baffle. The produced water is then either injected back into the oil reservoir, disposed of or treated. The bulk level (gas - liquid interface) and the oil water interfaced are determined using instrumentation fixed to the vessel. Valves on the oil and water outlets are controlled to ensure the interfaces are kept at their optimum levels for separation to occur. The Separator will only achieve bulk separation. The smaller droplets of water will not settle by gravity and will remain in the oil stream. Normally the oil from the separator is routed to a coalescer to further reduce the water content. [edit] Separation of Water From Oil
The production of water with oil continues to be a problem for engineers and the oil producers. Since 1865 when water was coproduced with hydrocarbons, it has challenged and frustrated the industry on how to separate the valuable from the disposable. According to Rehm et al (1983),[4] innovation over the years has lead from the skim pit to installation of the stock tank, to the gunbarrel, to the freewater knockout, to the hay-packed coalescer and most recently to the Performax Matrix Plate Coalescer, an enhanced gravity settling separator. The history of water treating for the most part has been sketchy and spartan. There is little economic value to the produced water, and it represents an extra cost for the producer to arrange for its disposal. Today oil fields produce greater quantities of water than they produce oil. Along with greater water production are emulsions and dispersions which are more difficult to treat. The separation process becomes interlocked with a myriad of contaminants as the last drop of oil is being recovered from the reservoir. In some instances it is preferable to separate and to remove water from the well fluid before it flows through pressure reductions, such as those caused by chokes and valves. Such water removal may prevent difficulties that could be caused downstream by the water, such as corrosion which can be referred to as being a chemical reactions that occurs whenever a gas or liquid chemically attacks an exposed metallic surface.[5] Corrosion is usually accelerated by warm temperatures and likewise by the presence of acids and salts. Other factors that affect the removal of water from oil include hydrate formation and the formation of tight emulsion that may be difficult to resolve into oil and water. The water can be separated from the oil in a three-phase separator by use of chemicals and gravity separation. If the three-phase separator is not large enough to separate the water adequately, it can be separated in a free-water knockout vessel installed upstream or downstream of the separators. [edit] Secondary Functions of Oil and Gas Separators
[edit] Maintenance of Optimum Pressure on Separator
For an oil and gas separator to accomplish its primary functions, pressure must be maintained in the separator so that the liquid and gas can be discharged into their respective processing or gathering systems. Pressure is maintained on the separator by use of a gas backpressure valve on each separator or with one master backpressure valve that controls the pressure on a battery of two or more separators. The optimum pressure to maintain on a separator is the pressure that will result in the highest economic yield from the sale of the liquid and gaseous hydrocarbons. [edit] Maintenance of Liquid Seal in Separator
To maintain pressure on a separator, a liquid seal must be effected in the lower portion of the vessel. This liquid seal prevents loss of gas with the oil and requires the use of a liquid-level controller and a valve. [edit] Methods Used To Remove Oil From Gas in Separators
Effective oil-gas separation is important not only to ensure that the required export quality is achieved but also to prevent problems in downstream process equipment and compressors. Once the bulk liquid has been knocked out, which can be achieved in many ways, the remaining liquid droplets are separated from by a demisting device. Until recently the main technologies used for this application were reverse-flow cyclones, mesh pads and vane packs. More recently new devices with higher gas-handling have been developed which have enabled potential reduction in the scrubber vessel size. There are several new concepts currently under development in which the fluids are degassed upstream of the primary separator. These systems are based on centrifugal and turbine technology and have additional advantages in that they are compact and motion insensitive, hence ideal for floating production facilities.[6] Below are some of the ways in which oil is separated from gas in separators. [edit] Density Difference (Gravity Separation)
Natural gas is lighter than liquid hydrocarbon. Minute particles of liquid hydrocarbon that are temporarily suspended in a stream of natural gas will, by density difference or force of gravity, settle out of the stream of gas if the velocity of the gas is sufficiently slow. The larger droplets of hydrocarbon will quickly settle out of the gas, but the smaller ones will take longer. At standard conditions of pressure and temperature, the droplets of liquid hydrocarbon may have a density 400 to 1,600 times that of natural gas. However, as the operating pressure and temperature increase, the difference in density decreases. At an operating pressure of 800 psig, the liquid hydrocarbon may be only 6 to 10 times as dense as the gas. Thus, operating pressure materially affects the size of the separator and the size and type of mist extractor required to separate adequately the liquid and gas. The fact that the liquid droplets may have a density 6 to 10 times that of the gas may indicate that droplets of liquid would quickly settle out of and separate from the gas. However, this may not occur because the particles of liquid may be so small that they tend to “float” in the gas and may not settle out of the gas stream in the short period of time the gas is in the oil and gas separator. As the operating pressure on a separator increases, the density difference between the liquid and gas decreases. For this reason, it is desirable to operate oil and gas separators at as low a pressure as is consistent with other process variables, conditions, and requirements. [edit] Impingement
If a flowing stream of gas containing liquid, mist is impinged against a surface, the liquid mist may adhere to and coalesce on the surface. After the mist coalesces into larger droplets, the droplets will gravitate to the liquid section of the vessel. If the liquid content of the gas is high, or if the mist particles are extremely fine, several successive impingement surfaces may be required to effect satisfactory removal of the mist. [edit] Change of Flow Direction
When the direction of flow of a gas stream containing liquid mist is changed abruptly, inertia causes the liquid to continue in the original direction of flow. Separation of liquid mist from the gas thus can be effected because the gas will more readily assume the change of flow direction and will flow away from the liquid mist particles. The liquid thus removed may coalesce on a surface or fall to the liquid section below. [edit] Change of Flow Velocity
Separation of liquid and gas can be effected with either a sudden increase or decrease in gas velocity. Both conditions use the difference in inertia of gas and liquid. With a decrease in velocity, the higher inertia of the liquid mist carries it forward and away from the gas.[7] The liquid may then coalesce on some surface and gravitate to the liquid section of the separator. With an increase in gas velocity, the higher inertia of the liquid causes the gas to move away from the liquid, and the liquid may fall to the liquid section of the vessel. [edit] Centrifugal Force
If a gas stream carrying liquid mist flows in a circular motion at sufficiently high velocity, centrifugal force throws the liquid mist outward against the walls of the container. Here the liquid coalesces into progressively larger droplets and finally gravitates to the liquid section below. Centrifugal force is one of the most effective methods of separating liquid mist from gas. However, according to Keplinger (1931),[8] some separator designers have pointed out a disadvantage in that a liquid with a free surface rotating as a whole will have its surface curved around its lowest point lying on the axis of rotation. This created false level may cause difficulty in regulating the fluid level control on the separator. This is largely overcome by placing vertical quieting baffles which should extend from the bottom of the separator to above the outlet. Efficiency of this type of mist extractor increases as the velocity of the gas stream increases. Thus for a given rate of throughput, a smaller centrifugal separator will suffice. [edit] Methods Used To Remove Gas From Oil in Separators
Because of higher prices for natural gas, the widespread reliance on metering of liquid hydrocarbons, and other reasons, it is important to remove all nonsolution gas from crude oil during field processing. Methods used to remove gas from crude oil in oil and gas separators are discussed below: [edit] Settling
Gas contained in crude oil that is not in solution in the oil will usually separate from the oil if allowed to settle a sufficient length of time. An increase in retention time for a given liquid
throughput requires an increase in the size of the vessel and/or an increase in the liquid depth in the separator. Increasing the depth of oil in the separator may not result in increased emission of nonsolution gas from the oil because “stacking up” of the oil may prevent the gas from emerging. Optimum removal of gas from the oil is usually obtained when the body of oil in the separator is thin i.e., when the ratio of surface area to retained oil volume is high. [edit] Agitation
Moderate, controlled agitation which can be defined as movement of the crude oil with sudden force[9] is usually helpful in removing nonsolution gas that may be mechanically locked in the oil by surface tension and oil viscosity. Agitation usually will cause the gas bubbles to coalesce and to separate from the oil in less time than would be required if agitation were not used. [edit] Heat
Heat as a form of energy that is transferred from one body to another results in a difference in temperature.[10] This reduces surface tension and viscosity of the oil and thus assists in releasing gas that is hydraulically retained in the oil. The most effective method of heating crude oil is to pass it through a heated-water bath. A spreader plate that disperses the oil into small streams or rivulets increases the effectiveness of the heated-water bath. Upward flow of the oil through the water bath affords slight agitation, which is helpful in coalescing and separating entrained gas from the oil. A heated-water bath is probably the most effective method of removing foam bubbles from foaming crude oil. A heated-water bath is not practical in most oil and gas separators, but heat can be added to the oil by direct or indirect fired heaters and/or heat exchangers, or heated free-water knockouts or emulsion treaters can be used to obtain a heatedwater bath. [edit] Centrifugal Force
Centrifugal force which can be defined as a fictitious force, peculiar to a particle moving on a circular path, that has the same magnitude and dimensions as the force that keeps the particle on its circular path (the centripetal force) [11] but points in the opposite direction is effective in separating gas from oil. The heavier oil is thrown outward against the wall of the vortex retainer
while the gas occupies the inner portion of the vortex. A properly shaped and sized vortex will allow the gas to ascend while the liquid flows downward to the bottom of the unit. [edit] Flow Measurements in Oil and Gas Separators
The direction of flow in and around a separator along with other flow instruments are usually illustrated on the Piping and instrumentation diagram, (P&ID). Some of these flow instruments include the Flow Indicator (FI), Flow Transmitter (FT) and the Flow Controller (FC). Flow is of paramount importance in the oil and gas industry because flow, as a major process variable is essentially important in that its understanding helps engineers come up with better designs and enables them to confidently carry out additional research. Mohan et al (1999) [12] carried out a research into the design and development of separators for a three-phase flow system. The purpose of the study was to investigate the complex multiphase hydrodynamic flow behaviour in a three-phase oil and gas separator. A mechanistic model was developed alongside a computational fluid dynamics (CFD) simulator. These were then used to carry out a detailed experimentation on the three-phase separator. The experimental and CFD simulation results were suitably integrated with the mechanistic model. The simulation time for the experiment was 20 seconds with the oil specific gravity as 0.885, and the separator lower part length and diameter were 4-ft and 3-inches respectively. The first set of experiment became a basis through which detailed investigations were used to carry out and to conduct similar simulation studies for different flow velocities and other operating conditions as well. [edit] Flow Calibration in Oil and Gas Separators
As earlier stated, flow instruments that function with the separator in an oil and gas environment include the flow indicator, flow transmitter and the flow controller. Due to maintenance (which will be discussed later) or due to high usage, these flowmeters do need to be calibrated from time to time.[13] Calibration can be defined as the process of referencing signals of known quantity that has been predetermined to suit the range of measurements required. Calibration can also be seen from a mathematical point of view in which the flowmeters are standardized by determining the deviation from the predetermined standard so as to ascertain the proper correction factors. In determining the deviation from the predetermined standard, the actual flowrate is usually first determined with the use of a master meter which is a type of flowmeter that has been calibrated with a high degree of accuracy or by weighing the flow so as to be able to obtain a gravimetric reading of the mass flow. Another type of meter used is the transfer meter. However, according to Ting et al (1989),[14] transfer meters have been proven to be less accurate if the operating conditions are different from its original calibrated points. According to Yoder (2000),[15] the
types of flowmeters used as master meters include turbine meters, positive displacement meters, venturi meters, and Coriolis meters. In the U.S., master meters are often calibrated at a flow lab that has been certified by the National Institute of Standards and Technology, (NIST). NIST certification of a flowmeter lab means that its methods have been approved by NIST. Normally, this includes NIST traceability, meaning that the standards used in the flowmeter calibration process have been certified by NIST or are causally linked back to standards that have been approved by NIST. However there is a general belief in the industry that the second method which involves the gravimetric weighing of the amount of fluid (liquid or gas) that actually flows through the meter into or out of a container during the calibration procedure is the most ideal method for measuring the actual amount of flow. Apparently, the weighing scale used for this method also has to be traceable to the National Institute of Standards and Technology (NIST) as well.[16] In ascertaining a proper correction factor, there is often no simple hardware adjustment to make the flowmeter start reading correctly. Instead, the deviation from the correct reading is recorded at a variety of flowrates. The data points are plotted, comparing the flowmeter output to the actual flowrate as determined by the standardized National Institute of Standards and Technology master meter or weigh scale. [edit] Controls, Valves, Accessories, and Safety Features for Oil and Gas Separators [edit] Controls
The controls required for oil and gas separators are liquid level controllers for oil and oil/water interface (three phase operation) and gas back-pressure control valve with pressure controller. Although the use of controls is expensive making the cost of operating fields with separators so high, installations has resulted in substantial savings in the overall operating expense as in the case of the 70 gas wells in the Big Piney, Wyo sighted by Fair (1968).[17] The wells with separators were located above 7,200 ft elevation, ranging upward to 9,000 ft. Control installations were sufficiently automated such that the field operations around the controllers could be operated from a remotecontrol station at the field office using the Distributed Control System. All in all, this improved the efficiency of personnel and the operation of the field, with a corresponding increase in production from the area. [edit] Valves
The valves required for oil and gas separators are oil discharge control valve, water-discharge control valve (three-phase operation), drain valves, block valves, pressure relief valves, and Emergency Shutdown valves (ESD). ESD valves typically stay in open position for months or years awaiting a command signal to operate. Little attention is paid to these valves outside of scheduled turnarounds. The pressures of continuous production often stretch these intervals even longer. This leads to build up or corrosion on these valves that prevents them from moving. For safety critical applications, it must be ensured that the valves operate upon demand.[18] [edit] Accessories
The accessories required for oil and gas separators are pressure gauges, thermometers, pressurereducing regulators (for control gas), level sight glasses, safety head with rupture disk, piping, and tubing. [edit] Safety Features for Oil and Gas Separators
Oil and gas separators should be installed at a safe distance from other lease equipment. Where they are installed on offshore platforms or in close proximity to other equipment, precautions should be taken to prevent injury to personnel and damage to surrounding equipment in case the separator or its controls or accessories fail. The following safety features are recommended for most oil and gas separators. High- and Low-Liquid-Level Controls:
High- and low liquid-level controls normally are float-operated pilots that actuate a valve on the inlet to the separator, open a bypass around the separator, sound a warning alarm, or perform some other pertinent function to prevent damage that might result from high or low liquid levels in the separator. High- and Low-Pressure Controls:
High- and low pressure controls are installed on separators to prevent excessively high or low pressures from interfering with normal operations. These high- and low-pressure controls can be mechanical, pneumatic, or electric and can sound a warning, actuate a shut-in valve, open a
bypass, or perform other pertinent functions to protect personnel, the separator, and surrounding equipment. High- and Low-Temperature Controls:
Temperature controls may be installed on separators to shut in the unit, to open or to close a bypass to a heater, or to sound a warning should the temperature in the separator become too high or too low. Such temperature controls are not normally used on separators, but they may be appropriate in special cases. According to Francis (1951), low-temperature controls in separators is another tools used by gas producers which finds its application in the high-pressure gas fields, usually referred to as "vapour-phase" reservoirs. Low temperatures obtainable from the expansion of these high-pressure gas streams are utilized to a profitable advantage. A more efficient recovery of the hydrocarbon condensate and a greater degree of dehydration of the gas as compared to the conventional heater and separator installation is a major advantage of lowtemperature controls in oil and gas separators.[19] Safety Relief Valves:
A spring-loaded safety relief valve is usually installed on all oil and gas separators. These valves normally are set at the design pressure of the vessel. Safety relief valves serve primarily as a warning, and in most instances are too small to handle the full rated fluid capacity of the separator. Full-capacity safety relief valves can be used and are particularly recommended when no safety head (rupture disk) is used on the separator. Safety Heads or Rupture Disks:
A safety head or rupture disk is a device containing a thin metal membrane that is designed to rupture when the pressure in the separator exceeds a predetermined value. This is usually from 1 1/4 to 1% times the design pressure of the separator vessel. The safety head disk is usually selected so that it will not rupture until the safety relief valve has opened and is incapable of preventing excessive pressure buildup in the separator. [edit] Operation and Maintenance Considerations for Oil and Gas Separators
Over the life of a production system, the separator is expected to process a wide range of produced fluids. With break through from water flood and expanded gas lift circulation, the
produced fluid water cut and gas-oil ratio is ever changing. In many instances, the separator fluid loading may exceed the original design capacity of the vessel. As a result, many operators find their separator no longer able to meet the required oil and water effluent standards, or experience high liquid carry-over in the gas according to Power et al (1990).[20] Some operational maintenance and considerations are discussed below: [edit] Periodic Inspection
In refineries and processing plants, it is normal practice to inspect all pressure vessels and piping periodically for corrosion and erosion. In the oil fields, this practice is not generally followed (DO NOT BELIEVE THIS TO BE TRUE), and equipment is replaced only after actual failure. This policy may create hazardous conditions for operating personnel and surrounding equipment. It is recommended that periodic inspection schedules for all pressure equipment be established and followed to protect against undue failures. [edit] Installation of Safety Devices
All safety relief devices should be installed as close to the vessel as possible and in such manner that the reaction force from exhausting fluids will not break off, unscrew, or otherwise dislodge the safety device. The discharge from safety devices should not endanger personnel or other equipment. [edit] Low Temperature
Separators should be operated above hydrate-formation temperature. Otherwise hydrates may form in the vessel and partially or completely plug it thereby reducing the capacity of the separator. In some instances when the liquid or gas outlet is plugged or restricted, this causes the safety valve to open or the safety head to rupture. Steam coils can be installed in the liquid section of oil and gas separators to melt hydrates that may form there. This is especially appropriate on low-temperature separators.
[edit] Corrosive Fluids
A separator handling corrosive fluid should be checked periodically to determine whether remedial work is required. Extreme cases of corrosion may require a reduction in the rated working pressure of the vessel. Periodic hydrostatic testing is recommended, especially if the fluids being handled are corrosive. Expendable anode can be used in separators to protect them against electrolytic corrosion. Some operators determine separator shell and head thickness with ultrasonic thickness indicators and calculate the maximum allowable working pressure from the remaining metal thickness. This should be done yearly offshore and every two to four years onshore.
Piping and instrumentation diagram From Wikipedia, the free encyclopedia Jump to: navigation, search
Piping and instrumentation diagram of pump with storage tank. Symbols according to EN ISO 10628 and EN 62424.
A piping and instrumentation diagram/drawing (P&ID) is a diagram in the process industry which shows the piping of the process flow together with the installed equipment and instrumentation.Contents [hide] 1 Contents and Function 2 List of P&ID items 3 Identification and Reference Designation 4 Symbols of chemical apparatus and equipment 5 See also 6 External links
[edit] Contents and Function
An example of a P&ID.
A piping and instrumentation diagram/drawing (P&ID) is defined by the Institute of Instrumentation and Control as follows: A diagram which shows the interconnection of process equipment and the instrumentation used to control the process. In the process industry, a standard set of symbols is used to prepare drawings of processes. The instrument symbols used in these drawings are generally based on International Society of Automation (ISA) Standard S5. 1. The primary schematic drawing used for laying out a process control installation.
P&IDs play a significant role in the maintenance and modification of the process that it describes. It is critical to demonstrate the physical sequence of equipment and systems, as well as how these systems connect. During the design stage, the diagram also provides the basis for the development of system control schemes, allowing for further safety and operational investigations, such as the hazard and operability study (HAZOP).
For processing facilities, it is a pictorial representation of Key piping and instrument details Control and shutdown schemes Safety and regulatory requirements Basic start up and operational information [edit] List of P&ID items Instrumentation and designations Mechanical equipment with names and numbers
All valves and their identifications Process piping, sizes and identification Miscellanea - vents, drains, special fittings, sampling lines, reducers, increasers and swagers Permanent start-up and flush lines Flow directions Interconnections references Control inputs and outputs, interlocks Interfaces for class changes Computer control system input Identification of components and subsystems delivered by others [edit] Identification and Reference Designation
The P&ID is used for the identification of measurements within the process. Identification letters for measurements are based on Standard ANSI/ISA S5.1 and ISO 14617-6:First-Letter Measurement A
Analysis
B
Burner, Combustion
C
User's Choice (usually Conductivity)
D
User's Choice (usually Density)
E
Voltage
F
Flow
G
User's Choice
H
Hand
I
Current
J
Power
K
Time, Time Schedule
L
Level
M
User's Choice
N
User's Choice (usually Torque)
O
User's Choice
P
Pressure
Q
Quantity
R
Radiation
S
Speed, Frequency
T
Temperature
U
User's Choice (usually Alarm Output)
V
Vibration, Mechanical Analysis
W
Weight, Force
X
User's Choice (usually on-off valve as XV)
Y
Event, State, Presence
Z
Position, Dimension
For reference designation of any equipment in industrial systems the standard IEC 61346 (Industrial systems, installations and equipment and industrial products — Structuring principles and reference designations) can be applied. For the function Measurement the reference designator B is used, followed by the above listed letter for the measured variable.
For reference designation of any equipment in a power station the KKS Power Plant Classification System can be applied. [edit] Symbols of chemical apparatus and equipment
Below are listed some symbols of chemical apparatus and equipment normally used in a P&ID, according to DIN 30600 and ISO 14617. Symbols of chemical apparatus and equipment Pipe Jacketed pipe Cooled or heated pipe
Thermally insulated pipe
Jacketed mixing vessel (autoclave) Half pipe mixing vessel Pressurized horizontal vessel Pressurized vertical vessel Pump
Vacuum pump or compressor
Fan
Axial fan
Bag
Radial fan
Packed column
Tray column
Furnace
Heat exchanger
Heat exchanger
Cooler
Gas bottle Dryer Cooling
tower Plate & frame heat
exchanger Double pipe heat exchanger U shaped tubes heat exchanger Covered gas vent
Fixed straight tubes heat exchanger Spiral heat exchanger Curved gas vent
(Air) filter
Funnel Steam trap Flexible pipe Valve Needle valve
Viewing glass
Control valve Butterfly valve
Pressure reducing valve
Manual valve
Back draft damper
Diaphragm valve
Ball
valve
[edit] See also Commons:Category:Chemical engineering symbols - A list of P&ID symbols in SVG format Process flow diagram [edit] External links
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Fluid dynamics From Wikipedia, the free encyclopedia Jump to: navigation, search Continuum mechanics
Laws[show] Solid mechanics[show] Fluid mechanics[hide] Fluids: Fluid statics · Fluid dynamics · Navier–Stokes equations · Bernoulli's principle · Buoyancy · Viscosity (Newtonian · Non-Newtonian) · Archimedes' principle · Pascal's law · Pressure · Liquids: Surface tension · Capillary action · Gases: Atmosphere · Boyle's law · Charles's law · GayLussac's law · Combined gas law · Plasma Rheology[show] Scientists[show] v·t·e
Typical aerodynamic teardrop shape, assuming a viscous medium passing from left to right, the diagram shows the pressure distribution as the thickness of the black line and shows the velocity in the boundary layer as the violet triangles. The green vortex generators prompt the transition to turbulent flow and prevent back-flow also called flow separation from the high pressure region in the back. The surface in front is as smooth as possible or even employs shark like skin, as any turbulence here will reduce the energy of the airflow. The truncation on the right, known as a Kammback, also prevents back flow from the high pressure region in the back across the spoilers to the convergent part.
In physics, fluid dynamics is a subdiscipline of fluid mechanics that deals with fluid flow— the natural science of fluids (liquids and gases) in motion. It has several subdisciplines itself, including aerodynamics (the study of air and other gases in motion) and hydrodynamics (the study of liquids in motion). Fluid dynamics has a wide range of applications, including calculating forces and moments on aircraft, determining the mass flow rate of petroleum through pipelines, predicting weather patterns, understanding nebulae in interstellar space and reportedly modeling fission weapon detonation. Some of its principles are even used in traffic engineering, where traffic is treated as a continuous fluid.
Fluid dynamics offers a systematic structure—which underlies these practical disciplines— that embraces empirical and semi-empirical laws derived from flow measurement and used to solve practical problems. The solution to a fluid dynamics problem typically involves calculating various properties of the fluid, such as velocity, pressure, density, and temperature, as functions of space and time.
Historically, hydrodynamics meant something different than it does today. Before the twentieth century, hydrodynamics was synonymous with fluid dynamics. This is still reflected in names of some fluid dynamics topics, like magnetohydrodynamics and hydrodynamic stability— both also applicable in, as well as being applied to, gases.[1]Contents [hide] 1 Equations of fluid dynamics 1.1 Compressible vs incompressible flow 1.2 Viscous vs inviscid flow 1.3 Steady vs unsteady flow
1.4 Laminar vs turbulent flow 1.5 Newtonian vs non-Newtonian fluids 1.6 Subsonic vs transonic, supersonic and hypersonic flows 1.7 Magnetohydrodynamics 1.8 Other approximations 2 Terminology in fluid dynamics 2.1 Terminology in incompressible fluid dynamics 2.2 Terminology in compressible fluid dynamics 3 See also 3.1 Fields of study 3.2 Mathematical equations and concepts 3.3 Types of fluid flow 3.4 Fluid properties 3.5 Fluid phenomena 3.6 Applications 3.7 Fluid dynamics journals 3.8 Miscellaneous 4 Notes 5 References 6 External links
[edit] Equations of fluid dynamics
The foundational axioms of fluid dynamics are the conservation laws, specifically, conservation of mass, conservation of linear momentum (also known as Newton's Second Law of
Motion), and conservation of energy (also known as First Law of Thermodynamics). These are based on classical mechanics and are modified in quantum mechanics and general relativity. They are expressed using the Reynolds Transport Theorem.
In addition to the above, fluids are assumed to obey the continuum assumption. Fluids are composed of molecules that collide with one another and solid objects. However, the continuum assumption considers fluids to be continuous, rather than discrete. Consequently, properties such as density, pressure, temperature, and velocity are taken to be well-defined at infinitesimally small points, and are assumed to vary continuously from one point to another. The fact that the fluid is made up of discrete molecules is ignored.
For fluids which are sufficiently dense to be a continuum, do not contain ionized species, and have velocities small in relation to the speed of light, the momentum equations for Newtonian fluids are the Navier-Stokes equations, which is a non-linear set of differential equations that describes the flow of a fluid whose stress depends linearly on velocity gradients and pressure. The unsimplified equations do not have a general closed-form solution, so they are primarily of use in Computational Fluid Dynamics. The equations can be simplified in a number of ways, all of which make them easier to solve. Some of them allow appropriate fluid dynamics problems to be solved in closed form.
In addition to the mass, momentum, and energy conservation equations, a thermodynamical equation of state giving the pressure as a function of other thermodynamic variables for the fluid is required to completely specify the problem. An example of this would be the perfect gas equation of state:
where p is pressure, ρ is density, Ru is the gas constant, M is the molar mass and T is temperature. [edit] Compressible vs incompressible flow
All fluids are compressible to some extent, that is, changes in pressure or temperature will result in changes in density. However, in many situations the changes in pressure and temperature
are sufficiently small that the changes in density are negligible. In this case the flow can be modeled as an incompressible flow. Otherwise the more general compressible flow equations must be used.
Mathematically, incompressibility is expressed by saying that the density ρ of a fluid parcel does not change as it moves in the flow field, i.e.,
where D/Dt is the substantial derivative, which is the sum of local and convective derivatives. This additional constraint simplifies the governing equations, especially in the case when the fluid has a uniform density.
For flow of gases, to determine whether to use compressible or incompressible fluid dynamics, the Mach number of the flow is to be evaluated. As a rough guide, compressible effects can be ignored at Mach numbers below approximately 0.3. For liquids, whether the incompressible assumption is valid depends on the fluid properties (specifically the critical pressure and temperature of the fluid) and the flow conditions (how close to the critical pressure the actual flow pressure becomes). Acoustic problems always require allowing compressibility, since sound waves are compression waves involving changes in pressure and density of the medium through which they propagate. [edit] Viscous vs inviscid flow
Potential flow around a wing
Viscous problems are those in which fluid friction has significant effects on the fluid motion.
The Reynolds number, which is a ratio between inertial and viscous forces, can be used to evaluate whether viscous or inviscid equations are appropriate to the problem.
Stokes flow is flow at very low Reynolds numbers, Re<<1, such that inertial forces can be neglected compared to viscous forces.
On the contrary, high Reynolds numbers indicate that the inertial forces are more significant than the viscous (friction) forces. Therefore, we may assume the flow to be an inviscid flow, an approximation in which we neglect viscosity completely, compared to inertial terms.
This idea can work fairly well when the Reynolds number is high. However, certain problems such as those involving solid boundaries, may require that the viscosity be included. Viscosity often cannot be neglected near solid boundaries because the no-slip condition can generate a thin region of large strain rate (known as Boundary layer) which enhances the effect of even a small amount of viscosity, and thus generating vorticity. Therefore, to calculate net forces on bodies (such as wings) we should use viscous flow equations. As illustrated by d'Alembert's paradox, a body in an inviscid fluid will experience no drag force. The standard equations of inviscid flow are the Euler equations. Another often used model, especially in computational fluid dynamics, is to use the Euler equations away from the body and the boundary layer equations, which incorporates viscosity, in a region close to the body.
The Euler equations can be integrated along a streamline to get Bernoulli's equation. When the flow is everywhere irrotational and inviscid, Bernoulli's equation can be used throughout the flow field. Such flows are called potential flows. [edit] Steady vs unsteady flow
Hydrodynamics simulation of the Rayleigh–Taylor instability [2]
When all the time derivatives of a flow field vanish, the flow is considered to be a steady flow. Steady-state flow refers to the condition where the fluid properties at a point in the system do not change over time. Otherwise, flow is called unsteady. Whether a particular flow is steady or unsteady, can depend on the chosen frame of reference. For instance, laminar flow over a sphere is steady in the frame of reference that is stationary with respect to the sphere. In a frame of reference that is stationary with respect to a background flow, the flow is unsteady.
Turbulent flows are unsteady by definition. A turbulent flow can, however, be statistically stationary. According to Pope:[3]
The random field U(x,t) is statistically stationary if all statistics are invariant under a shift in time.
This roughly means that all statistical properties are constant in time. Often, the mean field is the object of interest, and this is constant too in a statistically stationary flow.
Steady flows are often more tractable than otherwise similar unsteady flows. The governing equations of a steady problem have one dimension fewer (time) than the governing equations of the same problem without taking advantage of the steadiness of the flow field. [edit] Laminar vs turbulent flow
Turbulence is flow characterized by recirculation, eddies, and apparent randomness. Flow in which turbulence is not exhibited is called laminar. It should be noted, however, that the presence of eddies or recirculation alone does not necessarily indicate turbulent flow—these phenomena may be present in laminar flow as well. Mathematically, turbulent flow is often represented via a Reynolds decomposition, in which the flow is broken down into the sum of an average component and a perturbation component.
It is believed that turbulent flows can be described well through the use of the Navier– Stokes equations. Direct numerical simulation (DNS), based on the Navier–Stokes equations, makes it possible to simulate turbulent flows at moderate Reynolds numbers. Restrictions depend on the power of the computer used and the efficiency of the solution algorithm. The results of DNS have been found to agree well with experimental data for some flows.[4]
Most flows of interest have Reynolds numbers much too high for DNS to be a viable option,[5] given the state of computational power for the next few decades. Any flight vehicle large enough to carry a human (L > 3 m), moving faster than 72 km/h (20 m/s) is well beyond the limit of DNS simulation (Re = 4 million). Transport aircraft wings (such as on an Airbus A300 or Boeing 747) have Reynolds numbers of 40 million (based on the wing chord). In order to solve
these real-life flow problems, turbulence models will be a necessity for the foreseeable future. Reynolds-averaged Navier–Stokes equations (RANS) combined with turbulence modeling provides a model of the effects of the turbulent flow. Such a modeling mainly provides the additional momentum transfer by the Reynolds stresses, although the turbulence also enhances the heat and mass transfer. Another promising methodology is large eddy simulation (LES), especially in the guise of detached eddy simulation (DES)—which is a combination of RANS turbulence modeling and large eddy simulation. [edit] Newtonian vs non-Newtonian fluids
Sir Isaac Newton showed how stress and the rate of strain are very close to linearly related for many familiar fluids, such as water and air. These Newtonian fluids are modeled by a coefficient called viscosity, which depends on the specific fluid.
However, some of the other materials, such as emulsions and slurries and some viscoelastic materials (e.g. blood, some polymers), have more complicated non-Newtonian stress-strain behaviours. These materials include sticky liquids such as latex, honey, and lubricants which are studied in the sub-discipline of rheology. [edit] Subsonic vs transonic, supersonic and hypersonic flows
While many terrestrial flows (e.g. flow of water through a pipe) occur at low mach numbers, many flows of practical interest (e.g. in aerodynamics) occur at high fractions of the Mach Number M=1 or in excess of it (supersonic flows). New phenomena occur at these Mach number regimes (e.g. shock waves for supersonic flow, transonic instability in a regime of flows with M nearly equal to 1, non-equilibrium chemical behavior due to ionization in hypersonic flows) and it is necessary to treat each of these flow regimes separately. [edit] Magnetohydrodynamics Main article: Magnetohydrodynamics
Magnetohydrodynamics is the multi-disciplinary study of the flow of electrically conducting fluids in electromagnetic fields. Examples of such fluids include plasmas, liquid metals, and salt water. The fluid flow equations are solved simultaneously with Maxwell's equations of electromagnetism. [edit] Other approximations
There are a large number of other possible approximations to fluid dynamic problems. Some of the more commonly used are listed below. The Boussinesq approximation neglects variations in density except to calculate buoyancy forces. It is often used in free convection problems where density changes are small. Lubrication theory and Hele-Shaw flow exploits the large aspect ratio of the domain to show that certain terms in the equations are small and so can be neglected. Slender-body theory is a methodology used in Stokes flow problems to estimate the force on, or flow field around, a long slender object in a viscous fluid. The shallow-water equations can be used to describe a layer of relatively inviscid fluid with a free surface, in which surface gradients are small. The Boussinesq equations are applicable to surface waves on thicker layers of fluid and with steeper surface slopes. Darcy's law is used for flow in porous media, and works with variables averaged over several pore-widths. In rotating systems, the quasi-geostrophic approximation assumes an almost perfect balance between pressure gradients and the Coriolis force. It is useful in the study of atmospheric dynamics. [edit] Terminology in fluid dynamics
The concept of pressure is central to the study of both fluid statics and fluid dynamics. A pressure can be identified for every point in a body of fluid, regardless of whether the fluid is in motion or not. Pressure can be measured using an aneroid, Bourdon tube, mercury column, or various other methods.
Some of the terminology that is necessary in the study of fluid dynamics is not found in other similar areas of study. In particular, some of the terminology used in fluid dynamics is not used in fluid statics. [edit] Terminology in incompressible fluid dynamics
The concepts of total pressure and dynamic pressure arise from Bernoulli's equation and are significant in the study of all fluid flows. (These two pressures are not pressures in the usual sense—they cannot be measured using an aneroid, Bourdon tube or mercury column.) To avoid potential ambiguity when referring to pressure in fluid dynamics, many authors use the term static pressure to distinguish it from total pressure and dynamic pressure. Static pressure is identical to pressure and can be identified for every point in a fluid flow field.
In Aerodynamics, L.J. Clancy writes[6]: To distinguish it from the total and dynamic pressures, the actual pressure of the fluid, which is associated not with its motion but with its state, is often referred to as the static pressure, but where the term pressure alone is used it refers to this static pressure.
A point in a fluid flow where the flow has come to rest (i.e. speed is equal to zero adjacent to some solid body immersed in the fluid flow) is of special significance. It is of such importance that it is given a special name—a stagnation point. The static pressure at the stagnation point is of special significance and is given its own name—stagnation pressure. In incompressible flows, the stagnation pressure at a stagnation point is equal to the total pressure throughout the flow field. [edit] Terminology in compressible fluid dynamics
In a compressible fluid, such as air, the temperature and density are essential when determining the state of the fluid. In addition to the concept of total pressure (also known as stagnation pressure), the concepts of total (or stagnation) temperature and total (or stagnation) density are also essential in any study of compressible fluid flows. To avoid potential ambiguity when referring to temperature and density, many authors use the terms static temperature and
static density. Static temperature is identical to temperature; and static density is identical to density; and both can be identified for every point in a fluid flow field.
The temperature and density at a stagnation point are called stagnation temperature and stagnation density.
A similar approach is also taken with the thermodynamic properties of compressible fluids. Many authors use the terms total (or stagnation) enthalpy and total (or stagnation) entropy. The terms static enthalpy and static entropy appear to be less common, but where they are used they mean nothing more than enthalpy and entropy respectively, and the prefix "static" is being used to avoid ambiguity with their 'total' or 'stagnation' counterparts. Because the 'total' flow conditions are defined by isentropically bringing the fluid to rest, the total (or stagnation) entropy is by definition always equal to the "static" entropy. [edit] See also [edit] Fields of study
Joule–Thomson effect From Wikipedia, the free encyclopedia Jump to: navigation, search Throttling process redirects here. For the regulation of computing resources, see throttling process (computing).
In thermodynamics, the Joule–Thomson effect or Joule–Kelvin effect or Kelvin–Joule effect or Joule–Thomson expansion describes the temperature change of a gas or liquid when it is forced through a valve or porous plug while kept insulated so that no heat is exchanged with the environment.[1][2][3] This procedure is called a throttling process or Joule–Thomson process.[4] At room temperature, all gases except hydrogen, helium and neon cool upon expansion by the Joule–Thomson process.[5][6]
The effect is named for James Prescott Joule and William Thomson, 1st Baron Kelvin who discovered it in 1852 following earlier work by Joule on Joule expansion, in which a gas undergoes free expansion in a vacuum.
In the Joule experiment, the gas expands in a vacuum and the temperature drop of the system is zero, if the gas were ideal.
The throttling process is of the highest technical importance. It is at the heart of thermal machines such as refrigerators, air conditioners, heat pumps, and liquefiers.[7] Furthermore, throttling is a fundamentally irreversible process. The throttling due to the flow resistance in supply lines, heat exchangers, regenerators, and other components of (thermal) machines is a source of losses that limits the performance.Contents [hide] 1 Description 2 Physical mechanism 3 The Joule–Thomson (Kelvin) coefficient 4 Applications 5 Proof that the specific enthalpy remains constant 6 Throttling in the Ts diagram 7 Derivation of the Joule–Thomson (Kelvin) coefficient 8 See also 9 References 10 Bibliography 11 External links
[edit] Description
The adiabatic (no heat exchanged) expansion of a gas may be carried out in a number of ways. The change in temperature experienced by the gas during expansion depends not only on the initial and final pressure, but also on the manner in which the expansion is carried out. If the expansion process is reversible, meaning that the gas is in thermodynamic equilibrium at all times, it is called an isentropic expansion. In this scenario, the gas does positive work during the expansion, and its temperature decreases. In a free expansion, on the other hand, the gas does no work and absorbs no heat, so the internal energy is conserved. Expanded in this manner, the temperature of an ideal gas would remain constant, but the temperature of a real gas may either increase or decrease, depending on the initial temperature and pressure. The method of expansion discussed in this article, in which a gas or liquid at pressure P1 flows into a region of lower pressure P2 via a valve or porous plug under steady state conditions and without change in kinetic energy, is called the Joule–Thomson process. During this process, enthalpy remains unchanged (see a proof below).
A throttling process proceeds along a constant-enthalpy line in the direction of decreasing pressure, which means that the process occurs from left to right on a T-P diagram. As we proceed along a constant-enthalpy line from high enough pressures the temperature increases, until the inversion temperature. After this, as the fluid continues its expansion, the temperature drops. If we do this for several constant enthalpies and join the inversion points a line called the inversion line is obtained. This line intersects the T-axis at some temperature, named the maximum inversion temperature. For hydrogen this temperature is -68° C. In Vapour-compression refrigeration we need to throttle the gas and cool it at the same time. This poses a problem for substances whose maximum inversion temperature is well below room temperature. Thus hydrogen must be cooled below its inversion temperature if any cooling is achieved by throttling.[8]
Thermodynamic Interpretation of the experiment:
If we consider that certain amount of gas has passed through the porous plug then the pressure and temperature on the left side of the porous plug are P1 and T1 and a certain volume of V1.
On the right a similar amount of the gas will be at a pressure of P2, the temperature T2 and will occupy a volume V2.
As the gas is compressed the work done on the gas is P1V1 and the resultant work done by the gas during this expansion is P2V2. This gives a relation for work done as W = P2V2 - P1V1 [edit] Physical mechanism
As a gas expands, the average distance between molecules grows. Because of intermolecular attractive forces (see Van der Waals force), expansion causes an increase in the potential energy of the gas. If no external work is extracted in the process and no heat is transferred, the total energy of the gas remains the same because of the conservation of energy. The increase in potential energy thus implies a decrease in kinetic energy and therefore in temperature.
A second mechanism has the opposite effect. During gas molecule collisions, kinetic energy is temporarily converted into potential energy. As the average intermolecular distance increases, there is a drop in the number of collisions per time unit, which causes a decrease in average potential energy. Again, total energy is conserved, so this leads to an increase in kinetic energy (temperature). Below the Joule–Thomson inversion temperature, the former effect (work done internally against intermolecular attractive forces) dominates, and free expansion causes a decrease in temperature. Above the inversion temperature, gas molecules move faster and so collide more often, and the latter effect (reduced collisions causing a decrease in the average potential energy) dominates: Joule–Thomson expansion causes a temperature increase.
[edit] The Joule–Thomson (Kelvin) coefficient
Fig.1 Joule-Thomson coefficients for various gases at atmospheric pressure.
The rate of change of temperature with respect to pressure in a Joule–Thomson process (that is, at constant enthalpy ) is the Joule–Thomson (Kelvin) coefficient . This coefficient can be expressed in terms of the gas's volume , its heat capacity at constant pressure , and its coefficient of thermal expansion as:[1][3][9]
See the Derivation of the Joule–Thomson (Kelvin) coefficient below for the proof of this relation. The value of is typically expressed in °C/bar (SI units: K/Pa) and depends on the type of gas and on the temperature and pressure of the gas before expansion. Its pressure dependence is usually only a few percent for pressures up to 100 bar.
All real gases have an inversion point at which the value of changes sign. The temperature of this point, the Joule–Thomson inversion temperature, depends on the pressure of the gas before expansion.
In a gas expansion the pressure decreases, so the sign of is negative by definition. With that in mind, the following table explains when the Joule–Thomson effect cools or warms a real gas:If the gas temperature is then is since is thus must be so the gas below the inversion temperature
positivealways negative
above the inversion temperature
negative
negative
always negative
cools
positivewarms
Helium and hydrogen are two gases whose Joule–Thomson inversion temperatures at a pressure of one atmosphere are very low (e.g., about 51 K (−222 °C) for helium). Thus, helium and hydrogen warm up when expanded at constant enthalpy at typical room temperatures. On the other hand nitrogen and oxygen, the two most abundant gases in air, have inversion temperatures of 621 K (348 °C) and 764 K (491 °C) respectively: these gases can be cooled from room temperature by the Joule–Thomson effect.[1]
For an ideal gas, is always equal to zero: ideal gases neither warm nor cool upon being expanded at constant enthalpy. [edit] Applications
In practice, the Joule–Thomson effect is achieved by allowing the gas to expand through a throttling device (usually a valve) which must be very well insulated to prevent any heat transfer to or from the gas. No external work is extracted from the gas during the expansion (the gas must not be expanded through a turbine, for example).
The effect is applied in the Linde technique as a standard process in the petrochemical industry, where the cooling effect is used to liquefy gases, and also in many cryogenic applications (e.g. for the production of liquid oxygen, nitrogen, and argon). Only when the Joule–Thomson coefficient for the given gas at the given temperature is greater than zero can the gas be liquefied at that temperature by the Linde cycle. In other words, a gas must be below its inversion temperature to be liquefied by the Linde cycle. For this reason, simple Linde cycle liquefiers cannot normally be used to liquefy helium, hydrogen, or neon. [edit] Proof that the specific enthalpy remains constant
In thermodynamics so-called "specific" quantities are quantities per kilogram and are denoted by lower-case characters. So h, u, and v are the enthalpy, internal energy, and volume per kilogram, respectively. In a Joule–Thomson process the specific enthalpy h remains constant.[10] To prove this, the first step is to compute the net work done when a mass m of the gas moves through the plug. This amount of gas has a volume of V1 = m v1 in the region at pressure P1 (region 1) and a volume V2 = m v2 when in the region at pressure P2 (region 2). Then the work done on the gas by the rest of the gas in region 1 is = m P1v1. In region 2 the amount of work done by the gas is m P2v2. So, the total work done by the gas is
The change in internal energy plus the work done by the gas is, by the first law of thermodynamics, the total amount of heat absorbed by the gas (here it is assumed that there is no change in kinetic energy). In the Joule–Thomson process the gas is insulated, so no heat is absorbed. This means that
where u1 and u2 denote the specific internal energies of the gas in regions 1 and 2, respectively. Using the definition of the specific enthalpy h = u + Pv, the above equation implies that
where h1 and h2 denote the specific enthalpies of the gas in regions 1 and 2, respectively.
Fig.2 Ts diagram of nitrogen. The red dome represents the two-phase region with the low-entropy side the saturated liquid and the high-entropy side the saturated gas. The black curves give the Ts relation along isobars. The pressures are indicated in bar. The blue curves are isenthalps (curves of constant specific enthalpy). The values are indicated in blue in kJ/kg. The specific points a, b, etc, are treated in the main text. [edit] Throttling in the Ts diagram
A very convenient way to get a quantitative understanding of the throttling process is by using diagrams. There are many types of diagrams (hT, hP, etc.). Commonly used are the so-called Tsdiagrams. Fig.2 is the Ts-diagram of nitrogen as an example.[11] In Fig.2 various points are indicated as follows: a T = 300 K, p = 200 bar, s = 5.16 kg/(kgK), h = 430 kJ/kg; b T = 270 K, p = 1 bar, s = 6.79 kg/(kgK), h = 430 kJ/kg; c T = 133 K, p = 200 bar, s = 3.75 kg/(kgK), h = 150 kJ/kg; d T = 77.2 K, p = 1 bar, s = 4.40 kg/(kgK), h = 150 kJ/kg; e T = 77.2 K, p = 1 bar, s = 2.83 kg/(kgK), h = 28 kJ/kg (saturated liquid at 1 bar); f T = 77.2 K, p = 1 bar, s = 5.41 kg/(kgK), h =230 kJ/kg (saturated gas at 1 bar);
As shown before, throttling keeps h constant. E.g. throttling from 200 bar and 300 K (point a in Fig.2) follows the isenthalp (line of constant specific enthalpy) of 430 kJ/kg. At 1 bar it results in point b which has a temperature of 270 K. So throttling from 200 to 1 bar gives a cooling from room temperature to below the freezing point of water. Throttling from 200 bar and an initial temperature of 133 K (point c in Fig.2) to 1 bar results in point d, which is in the two-phase region of nitrogen at a temperature of 72.2 K. Since the enthalpy is an extensive parameter the enthalpy in d (hd) is equal to the enthalpy in e (he) multiplied with the liquid fraction in d (xd) plus the enthalpy in f (hf) multiplied with the gas fraction in d (1-xd). So
With numbers: 150 = xd 28 + (1 - xd) 230 so xd is about 0.40. This means that the mass fraction of the liquid in the liquid-gas mixture leaving the throttling valve is 40%. [edit] Derivation of the Joule–Thomson (Kelvin) coefficient
In this Section a derivation of the formula
for the Joule–Thomson (Kelvin) coefficient is given.
The partial derivative of T with respect to P at constant H can be computed by expressing the differential of the enthalpy, dH, in terms of dT and dP, and solving for the ratio of dT and dP with dH = 0. The differential of the enthalpy is given by:
Here, S is the entropy of the gas. Expressing dS in terms of dT and dP gives:
Using
(see Specific heat capacity) we can write:
The remaining partial derivative of S can be expressed in terms of the coefficient of thermal expansion via a Maxwell relation as follows. The differential of the Gibbs energy is given by:
The symmetry of partial derivatives of G with respect to T and P implies that:
where α is the cubic coefficient of thermal expansion. Using this relation dH can be expressed as
Solving for by equating dH to zero gives:
It is easy to verify that for an ideal gas αT = 1, so the temperature change of an ideal gas at a Joule–Thomson expansion is zero. The cooling of a gas by pure isentropic expansion (a reversible adiabatic process where work, done by gas-expansion, causes it to cool) is not Joule-Thomson cooling. [edit] See also Critical temperature Ideal gas Enthalpy and Isenthalpic Refrigeration Reversible process (thermodynamics) [edit] References
^ a b c R. H. Perry and D. W. Green (1984). Perry's Chemical Engineers' Handbook. McGraw-Hill. ISBN 0-07-049479-7. ^ B. N. Roy (2002). Fundamentals of Classical and Statistical Thermodynamics. John Wiley & Sons. ISBN 0-470-84313-6. ^ a b W. C. Edmister, B. I. Lee (1984). Applied Hydrocarbon Thermodynamics. Vol. 1 (2nd ed.). Gulf Publishing. ISBN 0-87201-855-5. ^ F. Reif (1965). "Chapter 5 – Simple applications of macroscopic thermodynamics". Fundamentals of Statistical and Thermal Physics. McGraw-Hill. ISBN 0-07-051800-9. ^ A. W. Adamson (1973). "Chapter 4 – Chemical thermodynamics. The First Law of Thermodynamics". A textbook of Physical Chemistry (1st ed.). Academic press. LCCN 720328. ^ G. W. Castellan (1971). "Chapter 7 – Energy and the First Law of Thermodynamics; Thermochemistry". Physical Chemistry (2nd ed.). Addison-Wesley. ISBN 0-201-00912-9. ^ M.J. Moran and H.N. Shapiro "Fundamentals of Engineering Thermodynamics" 5th Edition (2006) John Wiley & Sons, Inc. ^ Thermodynamics An Engineering Approach (6th ed.). McGraw Hills. 2007. ^ W.R. Salzman. "Joule Expansion". Department of Chemistry, University of Arizona. ^ See e.g. M.J. Moran and H.N. Shapiro "Fundamentals of Engineering Thermodynamics" 5th Edition (2006) John Wiley & Sons, Inc. page 147 ^ Figure composed with data obtained with RefProp, NIST Standard Reference Database 23 [edit] Bibliography M. W. Zemansky (1968). Heat and Thermodynamics; An Intermediate Textbook. McGraw-Hill. pp. 182, 355. LCCN 670891. D. V. Schroeder (2000). An Introduction to Thermal Physics. Addison Wesley Longman. p. 142. ISBN 0-201-38027-7. C. Kittel, H. Kroemer (1980). Thermal Physics. W. H. Freeman. ISBN 0-7167-1088-9. [edit] External links Vapor–liquid separator
From Wikipedia, the free encyclopedia (Redirected from Vapor-liquid separator) Jump to: navigation, search
A typical vapor–liquid separator including commonly a de-entrainment pad and sometimes an inlet distributor
A vapor–liquid separator is a device used in several industrial applications to separate a vapor– liquid mixture.
For the common variety, gravity is utilized in a vertical vessel to cause the liquid to settle to the bottom of the vessel, where it is withdrawn.[1][2][3][4]
In low gravity environments such as a space station, a common liquid separator will not function because gravity is not usable as a separation mechanism. In this case, centrifugal force needs to be utilized in a spinning centrifugal separator to drive liquid towards the outer edge of the chamber for removal. Gaseous components migrate towards the center. The gas outlet may itself be surrounding by a spinning mesh screen or grating, so that any liquid that does approach the outlet strikes the grating, is accelerated, and thrown away from the outlet.Contents [hide] 1 Method of operation 1.1 Liquid level monitoring 2 Where vapor–liquid separators are used 3 Preventing pump damage 4 See also 5 References 6 External links
[edit] Method of operation
The vapor travels through the gas outlet at a design velocity which minimizes the entrainment of any liquid droplets in the vapor as it exits the vessel.
The feed to a vapor–liquid separator may also be a liquid that is being partially or totally flashed into a vapor and liquid as it enters the separator.
A vapor–liquid separator may also be referred to as a flash drum, knock-out drum, knock-out pot, compressor suction drum or compressor inlet drum.
When used to remove suspended water droplets from streams of air, a vapor-liquid separator is often called a demister. [edit] Liquid level monitoring
The separator is only effective as long as there is an air space inside the chamber. The separator can fail if either the mixed inlet is overwhelmed with supply material, or the liquid drain is unable to handle the volume of liquid being collected. The separator may therefore be combined with some other liquid level sensing mechanism such as a sight glass or float sensor. In this manner, both the supply and drain flow can be regulated to prevent the separator from becoming overloaded. [edit] Where vapor–liquid separators are used
Vapor–liquid separators are very widely used in a great many industries and applications, such as:
Natural-gas processing From Wikipedia, the free encyclopedia
(Redirected from Natural gas processing) Jump to: navigation, search
A natural-gas processing plant
Natural-gas processing is a complex industrial process designed to clean raw natural gas by separating impurities and various non-methane hydrocarbons and fluids to produce what is known as pipeline quality dry natural gas.[1]
Natural-gas processing begins at the well head. The composition of the raw natural gas extracted from producing wells depends on the type, depth, and location of the underground deposit and the geology of the area. Oil and natural gas are often found together in the same reservoir. The natural gas produced from oil wells is generally classified as associated-dissolved, meaning that the natural gas is associated with or dissolved in crude oil. Natural gas production absent any association with crude oil is classified as “non-associated.” In 2004, 75 percent of U.S. wellhead production of natural gas was non-associated.[2]
Most natural-gas production contains, to varying degrees, low molecular weight hydrocarbon compounds; examples include methane (CH4), ethane (C2H6), propane (C3H8) and butane (C4H10). Although these hydrocarbons exist in a liquid state at underground pressures, they will become gaseous at normal atmospheric pressure. Collectively, they are called natural gas liquids (NGLs). The natural gas extracted from coal reservoirs and mines (coalbed methane) is the primary exception, being essentially a mix of mostly methane and about 10 percent carbon dioxide (CO2) .
Natural-gas processing plants purify raw natural gas produced from underground gas fields or extracted at the surface from fluids produced by oil wells. A fully operational plant delivers pipeline-quality natural gas that can be used as fuel by residential, commercial and industrial consumers. In the plant, contaminants are removed and the NGL hydrocarbons are recovered for other commercial uses. For economic reasons, however, some plants may be designed to yield an intermediate product typically containing over 90 per cent pure methane and smaller amounts of nitrogen, carbon dioxide, and sometimes ethane. This can be further processed in downstream plants or used as feedstock for chemicals manufacturing.Contents [hide] 1 Types of raw-natural-gas wells
2 Contaminants in raw natural gas 3 Description of a natural-gas processing plant 4 Consumption 5 Applications of natural gas 6 References 7 External links 8 Further Reading
[edit] Types of raw-natural-gas wells
Raw natural gas comes primarily from any one of three types of wells: crude oil wells, gas wells, and condensate wells.
Natural gas that comes from crude oil wells is typically termed associated gas. This gas can have existed as a gas cap above the crude oil in the underground formation, or could have been dissolved in the crude oil.
Natural gas from gas wells and from condensate wells, in which there is little or no crude oil, is termed non-associated gas. Gas wells typically produce only raw natural gas, while condensate wells produce raw natural gas along with other low molecular weight hydrocarbons. Those that are liquid at ambient conditions (i.e., pentane and heavier) are called natural gas condensate (sometimes also called natural gasoline or simply condensate).
Natural gas is termed sweet gas when relatively free of hydrogen sulfide; however, gas that does contain hydrogen sulfide is called sour gas.
Raw natural gas can also come from methane deposits in the pores of coal seams, and especially in a more concentrated state of adsorption onto the surface of the coal itself. Such gas is referred to
as coalbed gas or coalbed methane (Coal seam gas in Australia). Coalbed gas has become an important source of energy in recent decades. [edit] Contaminants in raw natural gas
Raw natural gas typically consists primarily of methane (CH4), the shortest and lightest hydrocarbon molecule. It also contains varying amounts of: Heavier gaseous hydrocarbons: ethane (C2H6), propane (C3H8), normal butane (n-C4H10), isobutane (i-C4H10), pentanes and even higher molecular weight hydrocarbons. When processed and purified into finished by-products, all of these are collectively referred to as NGL (Natural Gas Liquids). Acid gases: carbon dioxide (CO2), hydrogen sulfide (H2S) and mercaptans such as methanethiol (CH3SH) and ethanethiol (C2H5SH). Other gases: nitrogen (N2) and helium (He). Water: water vapor and liquid water. Also dissolved salts and dissolved gases (acids). Liquid hydrocarbons: perhaps some natural gas condensate (also referred to as casinghead gasoline or natural gasoline) and/or crude oil. Mercury: very small amounts of mercury primarily in elemental form, but chlorides and other species are possibly present.[3] Radioactive gas: Naturally occurring radioactive material (NORM), including radon, can accumulate in specific locations within processing equipment. This can render piping and equipment radioactive over time.
The raw natural gas must be purified to meet the quality standards specified by the major pipeline transmission and distribution companies. Those quality standards vary from pipeline to pipeline and are usually a function of a pipeline system's design and the markets that it serves. In general, the standards specify that the natural gas: Be within a specific range of heating value (caloric value). For example, in the United States, it should be about 1035 ± 5% BTU per cubic foot of gas at 1 atmosphere and 60 degrees Fahrenheit (41 MJ ± 5% per cubic metre of gas at 1 atmosphere and 15.6 degrees Celsius).
Be delivered at or above a specified hydrocarbon dew point temperature (below which some of the hydrocarbons in the gas might condense at pipeline pressure forming liquid slugs that could damage the pipeline). Dew-point adjustment serves the reduction of the concentration of water and heavy hydrocarbons in natural gas to such an extent that no condensation occurs during the ensuing transport in the pipelines Be free of particulate solids and liquid water to prevent erosion, corrosion or other damage to the pipeline. Be dehydrated of water vapor sufficiently to prevent the formation of methane hydrates within the gas processing plant or subsequently within the sales gas transmission pipeline. A typical water content specification in the U.S. is that gas must contain no more than seven pounds of water per million cubic feet (MMCFD) of gas.[4][5] Contain no more than trace amounts of components such as hydrogen sulfide, carbon dioxide, mercaptans, and nitrogen. The most common specification for hydrogen sulfide content is 0.25 grain H2S per 100 cubic feet of gas, or approximately 4 ppm. Specifications for CO2 typically limit the content to no more than two or three percent. Maintain mercury at less than detectable limits (approximately 0.001 ppb by volume) primarily to avoid damaging equipment in the gas processing plant or the pipeline transmission system from mercury amalgamation and embrittlement of aluminum and other metals.[3][6][7] [edit] Description of a natural-gas processing plant
There are a great many ways in which to configure the various unit processes used in the processing of raw natural gas. The block flow diagram below is a generalized, typical configuration for the processing of raw natural gas from non-associated gas wells. It shows how raw natural gas is processed into sales gas pipelined to the end user markets.[8][9][10][11][12] It also shows how processing of the raw natural gas yields these byproducts: Natural-gas condensate Sulfur Ethane Natural-gas liquids (NGL): propane, butanes and C5+ (which is the commonly used term for pentanes plus higher molecular weight hydrocarbons)
Raw natural gas is commonly collected from a group of adjacent wells and is first processed at that collection point for removal of free liquid water and natural gas condensate. The condensate is usually then transported to an oil refinery and the water is disposed of as wastewater.
The raw gas is then pipelined to a gas processing plant where the initial purification is usually the removal of acid gases (hydrogen sulfide and carbon dioxide). There are many processes that are available for that purpose as shown in the flow diagram, but amine treating is the process that was historically used. However, due to a range of performance and environmental constraints of the amine process, a newer technology based on the use of polymeric membranes to separate the carbon dioxide and hydrogen sulfide from the natural gas stream has gained increasing acceptance.
The acid gases, if present, are removed by membrane or amine treating can then be routed into a sulfur recovery unit which converts the hydrogen sulfide in the acid gas into either elemental sulfur or sulfuric acid. Of the processes available for these conversions, the Claus process is by far the most well known for recovering elemental sulfur, whereas the conventional Contact process and the Wet sulfuric acid process are the most used technologies for recovering sulfuric acid. The residual gas from the Claus process is commonly called tail gas and that gas is then processed in a tail gas treating unit (TGTU) to recover and recycle residual sulfur-containing compounds back into the Claus unit. Again, as shown in the flow diagram, there are a number of processes available for treating the Claus unit tail gas and for that purpose a WSA Process is also very suitable since it can work autothermal on tail gasses.
The next step in the gas processing plant is to remove water vapor from the gas using either the regenerable absorption in liquid triethylene glycol (TEG)[5], commonly referred to as glycol dehydration, deliquescent chloride desiccants, and or a Pressure Swing Adsorption (PSA) unit which is regenerable adsorption using a solid adsorbent.[13] Other newer processes like membranes may also be considered.
Mercury is then removed by using adsorption processes (as shown in the flow diagram) such as activated carbon or regenerable molecular sieves.[3]
Although not common, nitrogen is sometimes removed and rejected using one of the three processes indicated on the flow diagram:
Cryogenic process[14] using low temperature distillation. This process can be modified to also recover helium, if desired. Absorption process[15] using lean oil or a special solvent[16] as the absorbent. Adsorption process using activated carbon or molecular sieves as the adsorbent. This process may have limited applicability because it is said to incur the loss of butanes and heavier hydrocarbons.
The next step is to recover the natural gas liquids (NGL) for which most large, modern gas processing plants use another cryogenic low temperature distillation process involving expansion of the gas through a turbo-expander followed by distillation in a demethanizing fractionating column.[17][18] Some gas processing plants use lean oil absorption process[15] rather than the cryogenic turbo-expander process.
The residue gas from the NGL recovery section is the final, purified sales gas which is pipelined to the end-user markets.
The recovered NGL stream is sometimes processed through a fractionation train consisting of three distillation towers in series: a deethanizer, a depropanizer and a debutanizer. The overhead product from the deethanizer is ethane and the bottoms are fed to the depropanizer. The overhead product from the depropanizer is propane and the bottoms are fed to the debutanizer. The overhead product from the debutanizer is a mixture of normal and iso-butane, and the bottoms product is a C5+ mixture. The recovered streams of propane, butanes and C5+ may be "sweetened" in a Merox process unit to convert undesirable mercaptans into disulfides and, along with the recovered ethane, are the final NGL by-products from the gas processing plant. Currently, most cryogenic plants do not include fractionation for economic reasons, and the NGL stream is instead transported as a mixed product to standalone fractionation complexes located near refineries or chemical plants that use the components for feedstock. In case laying pipeline is not possible for geographical reason,or the distance between source and consumer exceed 3000km, natural gas is then transported by ship as LNG (liquefied natural gas) and again converted into its gaseous state in the vicinity of the consumer.
[edit] Consumption
Natural gas consumption patterns, across nations, vary based on access. Countries with large reserves tend to handle the raw-material natural gas more generously, while countries with scarce or lacking resources tend to be more economical. Despite the considerable findings, the predicted availability of the natural-gas reserves has hardly changed. [edit] Applications of natural gas Fuel for industrial heating and desiccation process Fuel for the operation of public and industrial power stations Household fuel for cooking, heating and providing hot water Fuel for environmentally friendly compressed or liquid natural gas vehicles Raw material for chemical synthesis Raw material for large-scale fuel production using gas-to-liquid (GTL) process (e.g. to produce sulphur-and aromatic-free diesel with low-emission combustion) [edit] References
Pipeline transport From Wikipedia, the free encyclopedia Jump to: navigation, search This article needs additional citations for verification. Please help improve this article by adding citations to reliable sources. Unsourced material may be challenged and removed. (August 2008)
An elevated section of the Alaska Pipeline.
District heating pipeline in Austria with a length of 31 km [1]
Pipeline transport is the transportation of goods through a pipe. Most commonly, liquids and gases are sent, but pneumatic tubes using compressed air can also transport solid capsules .
As for gases and liquids, any chemically stable substance can be sent through a pipeline. Therefore sewage, slurry, water, or even beer pipelines exist; but arguably the most valuable are those transporting crude petroleum and refined petroleum product including fuels: oil (oleoduct), natural gas (gas grid), and biofuels.Contents [hide] 1 Types by transported substance 1.1 For oil or natural gas 1.2 For ammonia 1.3 For biofuels (ethanol and biobutanol) 1.4 For coal and ore 1.5 For hydrogen 1.6 For water 1.7 For beverages 1.7.1 For beer 1.8 For other uses 2 Types by transport function 3 Construction 4 Operation 5 Technology 5.1 Components 5.2 Leak detection systems 6 Implementation 7 Maintenance 8 Regulation 9 Pipelines and geopolitics
10 Dangers 10.1 Accidents 10.2 As targets 11 See also 12 References 13 External links
[edit] Types by transported substance [edit] For oil or natural gasPart of a series on Transport Modes Animal-powered · Aviation · Cable · Human-powered · Pipeline · Rail · Road · Ship · Space Topics History (Timeline) · Outline Transport portal v·t·e
See also: List of oil pipelines and List of natural gas pipelines
A "Pig" launcher/receiver, belonging to the natural gas pipeline in Switzerland.
There is some argument as to when the first crude oil pipeline was built. However, some[who?] say pipeline transport was pioneered by Vladimir Shukhov and the Branobel company in the late 19th century. Others[who?] say oil pipelines originated when the Oil Transport Association first constructed a 2-inch (51 mm) wrought iron pipeline over a 6-mile (9.7 km) track from an oil field in
Pennsylvania to a railroad station in Oil Creek, in the 1860s. Pipelines are generally the most economical way to transport large quantities of oil, refined oil products or natural gas over land. Natural gas is methane and is found in nature mixed with other gases, mainly propane and butane. LPG as propane or LP gas and butane are wet gases when under light pressure are liquids and thus are called Natural Gas Liquids or NGL's. Propane is considered the greenest transportation fuel because it does not require refining like gasoline or diesel fuel. Propane is just separated, not refined from methane and butane and other lesser gases at a processing facility which saves energy and time getting the final products to market. Propane mixed with sand, known as propant, is used for WATERLESS fracking, as it does not pollute water tables or soil and is recovered. These small NGL processing facilities can be located in oil fields so the
butane and propane liquid under light pressure of 125 pounds per square inch, can be shipped by rail, truck or pipeline. Propane can be used as a fuel in oil fields to heat various facilities used by the oil drillers or equipment and trucks used in the oil patch. EG: Propane will convert from a gas to a liquid under light pressure under 40 PSI, give or take depending on temperature, and is pumped into cars and trucks at less than 125 PSI at retail stations. Pipelines and rail cars use about double that pressure to pump at 250 PSI. To convert PSI pressure to metric pascals, multiply one PSI is 6,894.75 pascals which is the same as 2.0360 inches of mercury. The distance to ship propane to markets is much shorter as thousands of
NGL processing plants are located in oil fields or close by when a number of pipelines tie into each other from various relatively close fields. Many Bakken Basin oil companies in North Dakota, Montana, Manitoba and Saskatchewan gas fields separate the NGL's in the field, allowing the drillers to sell propane directly to small wholesalers, eliminating the large refinery control of product and prices for propane or butane. One oil company operating in the Bakken in ND, stated two weeks ago, that the estimate of 577 billion barrels of oil-gas in the Bakken, should be upgraded to 903 billion barrels. Yes, that is 0.903 trillion barrels of very light crude-gas mixture with it's oil rated at 43 degrees API. Light oil is rated at 41 degree API which is the American Petroleum Institute standard. Present industry figures show about 60 percent of propane-butane was produced
from gas fields while the other 40 percent was produced at oil refineries when a barrel of oil is cracked or refined into various products. With the huge amount of oil and gas fracking or fracing or fracture of oil bearing rock around North America over the past 6 years, i would estimate that now about 70 percent of propane-butane mixed with other NGL's, is produced from oil and gas
fields, with the balance of 30 percent of propane-butane produced from oil refineries when oil is cracked. Both propane used as auto fuel HD5 grade and butane, bring a higher value to any drilling company, so they explore the WET gas fields first, to bring in more money than a dryer gas well. The most recent major pipeline to start operating in North America,
is a TansCanada natural gas line going north across the Niagara region bridges with Marcellus shale gas from Pennsylvania and others tied in methane or nat gas sources, into the Canadian province of Ontario as of the fall of 2012, supplying 16 percent of all the natural gas used in Ontario. This new U.S. supplied nat gas displaces the nat gas formerly shipped to Ontario from western Canada in Alberta and Manitoba, thus dropping the government
regulated pipeline shipping charges because of the significantly shorter distance from gas source to consumer. Compared to shipping by railroad, pipelines have lower cost per unit and higher capacity. To avoid delays and U.S. government regulation, many small, medium and large
oil producers in North Dakota, have decided to run an oil pipeline north to Canada to meet up with a Canadian oil pipeline shipping oil from west to east. This allows the Bakken Basin and Three Forks oil producers to get higher negotiated prices for their oil because they will not be restricted to just one wholesale market in the U.S. The distance from the biggest oil patch in ND, is Williston, ND, only about 85 miles or 137 kilometers to the Canadian border and Manitoba. Mutual funds and joint ventures are big investors in new oil and gas pipelines as they are very long term and have set fees that both U.S and Canada that guarantee a profit to pipe the oil or gas or NGL. Recently in the fall of 2012, the U.S. is now exporting propane to Europe, known as LPG, as wholesale prices there are much higher than in North America. As more North American pipelines are built, even more exports of LNG, propane
and butane etc, will occur on all three U.S. coasts. To give insight, North Dakota's oil production has grown to 5 times in late 2012 compared to what it was just 6 years ago creating thousands of good paying long term jobs. ND oil companies are shipping huge amounts of oil by tanker rail car as they can direct the oil to the market that gives the best price but pipelines are cheaper. Rail cars can be used to avoid a congested oil pipeline to get the oil to a different pipeline and get the oil to market faster and different less busy oil refineries.
Canada is reversing and converting the major natural gas pipeline going from east-to-west and expanding it and using it to ship western Canadian oil eastward. From a presently rated 250,000 barrels equivalent per day pipeline, it will be expanded to between one million to 1.3 million barrels per day to ship oil instead of nat gas. Since this nat gas pipeline already exists, it will bring western oil to refineries in Ontario, Michigan, Ohio, PA, Quebec and New York by early 2014. New Brunswick will also refine some of this western Canadian crude and export
some crude and refined oil to Europe from it's deep water oil ULCC loading port. This oil will displace Brent crude imported into any U.S. eastern seaboard refinery, wanting to buy much cheaper North American oil, than importing it from overseas and Central and South America. The normal price spread between imported light Brent oil and WTI, West Texas Intermediate oil, is about $15 to $20 per barrel and as high as $30 in 2012. Alaska and Louisiana both have very light crude and the spot price for it is very close to the daily Brent price. As i write this today, December 17, 2012, West Texas Intermediate oil is
trading at $87.44 per barrel while Brent oil is $107.97 with both of those trades within 45 seconds of each other at 1:15PM eastern. Notice the spread of $20 per barrel. More pipelines will drop both the spot wholesale and long term contract prices of oil for eastern seaboard U.S and Canadian refineries. Refineries will be able to drop wholesale prices of gasoline, diesel fuel, home heating oil and jet fuel while making higher profits than they are making now once the western Canadian oil starts to flow east in the 2014 Q1 completed expanded oil pipeline. Some parts of that pipeline will be pumping oil sometime in 2013 to Ontario crossing into Port Huron, Michigan from Sarnia, Ontario. That oil pipeline, which also carries North Dakota crude oil through Canada, can be expanded to triple or quadruple it's planed one million barrel per day limit when required. This
Canadian oil pipeline is a huge threat to OPEC and their control of world market prices of crude oil. Maybe we should call this new supply of western oil COP, or Canadian Oil Price.
Although pipelines can be built under the sea, that process is economically and technically demanding, so the majority of oil at sea is transported by tanker ships.
The market size for oil and gas pipeline construction experienced tremendous growth prior to the economic downturn in 2008. The industry grew from $23 billion in 2006 to $39 billion in 2008.[2]
Oil pipelines are made from steel or plastic tubes with inner diameter typically from 4 to 48 inches (100 to 1,200 mm). Most pipelines are typically buried at a depth of about 3 to 6 feet (0.91 to 1.8 m). To protect pipes from impact, abrasion, and corrosion, a variety of methods are used. These can include wood lagging (wood slats), concrete coating, rockshield, high-density polyethylene, imported sand padding, and padding machines.[3]
The oil is kept in motion by pump stations along the pipeline, and usually flows at speed of about 1 to 6 metres per second (3.3 to 20 ft/s). Multi-product pipelines are used to transport two or more different products in sequence in the same pipeline. Usually in multi-product pipelines there is no physical separation between the different products. Some mixing of adjacent products occurs, producing interface, also known in the industry as "transmix." At the receiving facilities this interface is usually absorbed in one of the products based on pre-calculated absorption rates. Alternately, transmix may be diverted and shipped to facilities for separation of the commingled products.[4]
Crude oil contains varying amounts of paraffin wax and in colder climates wax buildup may occur within a pipeline. Often these pipelines are inspected and cleaned using pipeline inspection gauges, pigs, also known as scrapers or Go-devils. Smart pigs (also known as intelligent or intelligence pigs) are used to detect anomalies in the pipe such as dents, metal loss caused by corrosion, cracking or other mechanical damage.[5] These devices are launched from pig-launcher stations and travel through the pipeline to be received at any other station down-stream, either cleaning wax deposits and material that may have accumulated inside the line or inspecting and recording the condition of the line.
For natural gas, pipelines are constructed of carbon steel and vary in size from 2 to 60 inches (51 to 1,500 mm) in diameter, depending on the type of pipeline. The gas is pressurized by compressor stations and is odourless unless mixed with a mercaptan odorant where required by a regulating authority. [edit] For ammonia
Highly toxic ammonia is theoretically the most dangerous substance to be transported through long-distance pipelines. However, incidents on ammonia-transporting lines are uncommon - unlike on industrial ammonia-processing equipment.
The world's longest ammonia pipeline from Russia to Ukraine.
A major example of ammonia pipeline is the Ukrainian Transammiak line connecting the TogliattiAzot facility in Russia to the exporting Black Sea-port of Odessa. [edit] For biofuels (ethanol and biobutanol) See also: Biobutanol
Pipelines have been used for transportation of ethanol in Brazil, and there are several ethanol pipeline projects in Brazil and the United States.[6] Main problems related to the shipment of ethanol by pipeline are its high oxygen content, which makes it corrosive, and absorption of water and impurities in pipelines, which is not a problem with oil and natural gas.[6][7] Insufficient volumes and cost-effectiveness are other considerations limiting construction of ethanol pipelines.[7][8] [edit] For coal and ore
Slurry pipelines are sometimes used to transport coal or ore from mines. The material to be transported is closely mixed with water before being introduced to the pipeline; at the far end, the material must be dried. One example is a 525 km slurry pipeline which is planned to transport iron ore from the Minas-Rio mine (producing 26.5 million tonnes per year) to a port at Açu in Brazil.[9] An existing example is the 85 km Savage River Slurry pipeline in Tasmania, Australia, possibly the world's first when it was built in 1967. It includes a 366m bridge span at 167m above the Savage River.[10][11] [edit] For hydrogen Main article: Hydrogen pipeline transport
Hydrogen pipeline transport is a transportation of hydrogen through a pipe as part of the hydrogen infrastructure. Hydrogen pipeline transport is used to connect the point of hydrogen
production or delivery of hydrogen with the point of demand, with transport costs similar to CNG,[12] the technology is proven.[13] Most hydrogen is produced at the place of demand with every 50 to 100 miles (160 km) an industrial production facility.[14] The 1938 - Rhine-Ruhr 240 km hydrogen pipeline is still in operation.[15] As of 2004 there are 900 miles (1,400 km) of low pressure hydrogen pipelines in the USA and 930 miles (1,500 km) in Europe. [edit] For water
The Los Angeles Aqueduct in Antelope Valley. Main article: Aqueduct
Two millennia ago the ancient Romans made use of large aqueducts to transport water from higher elevations by building the aqueducts in graduated segments that allowed gravity to push the water along until it reached its destination. Hundreds of these were built throughout Europe and elsewhere, and along with flour mills were considered the lifeline of the Roman Empire. The ancient Chinese also made use of channels and pipe systems for public works. The famous Han Dynasty court eunuch Zhang Rang (d. 189 AD) once ordered the engineer Bi Lan to construct a series of square-pallet chain pumps outside the capital city of Luoyang.[16] These chain pumps serviced the imperial palaces and living quarters of the capital city as the water lifted by the chain pumps was brought in by a stoneware pipe system.[16][17]
Pipelines are useful for transporting water for drinking or irrigation over long distances when it needs to move over hills, or where canals or channels are poor choices due to considerations of evaporation, pollution, or environmental impact.
The 530 km (330 mi) Goldfields Water Supply Scheme in Western Australia using 750 mm (30 inch) pipe and completed in 1903 was the largest water supply scheme of its time.[18][19]
Examples of significant water pipelines in South Australia are the Morgan-Whyalla (completed 1944) and Mannum-Adelaide [20] (completed 1955) pipelines.
There are two Los Angeles, California aqueducts, the First Los Angeles Aqueduct (completed 1913) and the Second Los Angeles Aqueduct (completed 1970) which also include extensive use of pipelines.
The Great Manmade River of Libya supplies 3,680,000 cubic metres (4,810,000 cu yd) of water each day to Tripoli, Benghazi, Sirte, and several other cities in Libya. The pipeline is over 2,800 kilometres (1,700 mi) long, and is connected to wells tapping an aquifer over 500 metres (1,600 ft) underground.[21] [edit] For beverages [edit] For beer
Thor Pipeline in Randers, Denmark
Bars in the Veltins-Arena, a major football ground in Gelsenkirchen, Germany, are interconnected by a 5 km long beer pipeline. It is the favored method for distributing beer in such large stadiums, because the bars have to overcome big differences between demands during various stages of a match; this allows them to be supplied by a central tank.
In Randers city in Denmark, the so-called Thor beer pipeline still exists. Originally copper pipes were running directly from the brewery and, when in the 90s the brewery moved out of the city, Thor beer replaced the centre of a star with a giant tank. [edit] For other uses
The village of Hallstatt in Austria, which is known for its long history of salt mining, claims to contain "the oldest industrial pipeline in the world", dating back to 1595.[22] It was constructed from 13,000 hollowed-out tree trunks to transport salt water for 40 kilometers from Hallstatt to Ebensee.[23] [edit]
Types by transport function
In general, pipelines can be classified in three categories depending on purpose: Gathering pipelines Group of smaller interconnected pipelines forming complex networks with the purpose of bringing crude oil or natural gas from several nearby wells to a treatment plant or processing facility. In this group, pipelines are usually short- a couple of hundred metres- and with small diameters. Also sub-sea pipelines for collecting product from deep water production platforms are considered gathering systems. Transportation pipelines Mainly long pipes with large diameters, moving products (oil, gas, refined products) between cities, countries and even continents. These transportation networks include several compressor stations in gas lines or pump stations for crude and multiproducts pipelines. Distribution pipelines Composed of several interconnected pipelines with small diameters, used to take the products to the final consumer. Feeder lines to distribute gas to homes and businesses downstream. Pipelines at terminals for distributing products to tanks and storage facilities are included in this group. [edit] Construction
When a pipeline is built, the construction project not only covers the civil work to lay the pipeline and build the pump/compressor stations, it also has to cover all the work related to the installation of the field devices that will support remote operation.
The pipeline is routed along what is known as a "right of way". Pipelines are generally built using the following stages: Route (right of way) selection Surveying the route Clearing the route Trenching - Main Route and Crossings (roads, rail, other pipes, etc.)
Installing the pipe Installing valves, intersections, etc. Covering the pipe and trench
Russia has "Pipeline Troops" as part of the Rear Services, who are trained to build and repair pipelines. Russia is the only country to have Pipeline Troops.[24] [edit] Operation
Field devices are instrumentation, data gathering units and communication systems. The field Instrumentation includes flow, pressure and temperature gauges/transmitters, and other devices to measure the relevant data required. These instruments are installed along the pipeline on some specific locations, such as injection or delivery stations, pump stations (liquid pipelines) or compressor stations (gas pipelines), and block valve stations.
The information measured by these field instruments is then gathered in local Remote Terminal Units (RTU) that transfer the field data to a central location in real time using communication systems, such as satellite channels, microwave links, or cellular phone connections.
Pipelines are controlled and operated remotely, from what is usually known as The Main Control Room. In this center, all the data related to field measurement is consolidated in one central database. The data is received from multiple RTUs along the pipeline. It is common to find RTUs installed at every station along the pipeline.
The SCADA System for pipelines.
The SCADA system at the Main Control Room receives all the field data and presents it to the pipeline operator through a set of screens or Human Machine Interface, showing the operational conditions of the pipeline. The operator can monitor the hydraulic conditions of the line, as well as send operational commands (open/close valves, turn on/off compressors or pumps, change setpoints, etc.) through the SCADA system to the field.
To optimize and secure the operation of these assets, some pipeline companies are using what is called Advanced Pipeline Applications, which are software tools installed on top of the SCADA system, that provide extended functionality to perform leak detection, leak location, batch tracking (liquid lines), pig tracking, composition tracking, predictive modeling, look ahead modeling, operator training and more. [edit] Technology [edit] Components
The Trans Alaska Pipeline crossing under the Tanana River and over ridge of the Alaska Range
Pipeline networks are composed of several pieces of equipment that operate together to move products from location to location. The main elements of a pipeline system are: Initial injection station Known also as supply or inlet station, is the beginning of the system, where the product is injected into the line. Storage facilities, pumps or compressors are usually located at these locations. Compressor/pump stations Pumps for liquid pipelines and Compressors for gas pipelines, are located along the line to move the product through the pipeline. The location of these stations is defined by the topography of the terrain, the type of product being transported, or operational conditions of the network. Partial delivery station Known also as intermediate stations, these facilities allow the pipeline operator to deliver part of the product being transported. Block valve station These are the first line of protection for pipelines. With these valves the operator can isolate any segment of the line for maintenance work or isolate a rupture or leak. Block valve stations are usually located every 20 to 30 miles (48 km), depending on the type of pipeline. Even though it is not a design rule, it is a very usual practice in liquid pipelines. The location of these stations
depends exclusively on the nature of the product being transported, the trajectory of the pipeline and/or the operational conditions of the line. Regulator station This is a special type of valve station, where the operator can release some of the pressure from the line. Regulators are usually located at the downhill side of a peak. Final delivery station Known also as outlet stations or terminals, this is where the product will be distributed to the consumer. It could be a tank terminal for liquid pipelines or a connection to a distribution network for gas pipelines. [edit] Leak detection systems
Since oil and gas pipelines are an important asset of the economic development of almost any country, it has been required either by government regulations or internal policies to ensure the safety of the assets, and the population and environment where these pipelines run.
Pipeline companies face government regulation, environmental constraints and social situations. Government regulations may define minimum staff to run the operation, operator training requirements; pipeline facilities, technology and applications required to ensure operational safety. For example, in the State of Washington it is mandatory for pipeline operators to be able to detect and locate leaks of 8 percent of maximum flow within fifteen minutes or less. Social factors also affect the operation of pipelines. In third world countries, product theft is a problem for pipeline companies. It is common to find unauthorized extractions in the middle of the pipeline. In this case, the detection levels should be under two percent of maximum flow, with a high expectation for location accuracy.
Various technologies and strategies have been implemented for monitoring pipelines, from physically walking the lines to satellite surveillance. The most common technology to protect pipelines from occasional leaks is Computational Pipeline Monitoring or CPM. CPM takes information from the field related to pressures, flows, and temperatures to estimate the hydraulic behavior of the product being transported. Once the estimation is completed, the results are compared to other field references to detect the presence of an anomaly or unexpected situation, which may be related to a leak.
The American Petroleum Institute has published several articles related to the performance of CPM in liquids pipelines, the API Publications are: API 1130 – Computational pipeline monitoring for liquids pipelines API 1155 – Evaluation methodology for software based leak detection systems API 1149 – Pipeline variable uncertainties & their effects on leak detectability [edit] Implementation
As a rule pipelines for all uses are laid in most cases underground. However in some cases it is necessary to cross a valley or a river on a pipeline bridge. Pipelines for centralized heating systems are often laid on the ground or overhead. Pipelines for petroleum running through permafrost areas as Trans-Alaska-Pipeline are often run overhead in order to avoid melting the frozen ground by hot petroleum which would result in sinking the pipeline in the ground. [edit] Maintenance
Maintenance of pipelines includes checking Cathodic protection levels for the proper range, surveillance for construction, erosion, or leaks by foot, land vehicle, boat, or air, and running cleaning pigs, when there is anything carried in the pipeline that is corrosive.
US pipeline maintenance rules are covered in Code of Federal Regulations(CFR) sections, 49 CFR 192 for natural gas pipelines, and 49 CFR 195 for petroleum liquid pipelines. [edit] Regulation
An underground petroleum pipeline running through a park
In the US, onshore and offshore pipelines used to transport oil and gas are regulated by the Pipeline and Hazardous Materials Safety Administration (PHMSA). Certain offshore pipelines used to produce oil and gas are regulated by the Minerals Management Service (MMS). In Canada, pipelines are regulated by either the provincial regulators or, if they cross provincial boundaries or the Canada/US border, by the National Energy Board (NEB). Government regulations in Canada and the United States require that buried fuel pipelines must be protected from corrosion. Often, the most economical method of corrosion control is by use of pipeline coating in conjunction with cathodic protection and technology to monitor the pipeline. Above ground, cathodic protection is not an option. The coating is the only external protection. [edit] Pipelines and geopolitics
Pipelines for major energy resources (petroleum and natural gas) are not merely an element of trade. They connect to issues of geopolitics and international security as well, and the construction, placement, and control of oil and gas pipelines often figure prominently in state interests and actions. A notable example of pipeline politics occurred at the beginning of the year 2009, wherein a dispute between Russia and Ukraine ostensibly over pricing led to a major political crisis. Russian state-owned gas company Gazprom cut off natural gas supplies to Ukraine after talks between it and the Ukrainian government fell through. In addition to cutting off supplies to Ukraine, Russian gas flowing through Ukraine—which included nearly all supplies to Southeastern Europe and some supplies to Central and Western Europe—was cut off, creating a major crisis in several countries heavily dependent on Russian gas as fuel. Russia was accused of using the dispute as leverage in its attempt to keep other powers, and particularly the European Union, from interfering in its "near abroad".
Oil and gas pipelines also figure prominently in the politics of Central Asia and the Caucasus. [edit] Dangers [edit] Accidents
Pipelines conveying flammable or explosive material, such as natural gas or oil, pose special safety concerns.
For a more complete list see List of pipeline accidents June 16, 1976 - A gasoline pipeline was ruptured by a road construction crew in Los Angeles, California. Gasoline sprayed across the area, and soon ignited, killing 9, and injuring at least 14 others. Confusion over the depth of the pipeline in the construction area seemed to be a factor in the accident.[25] 1982 - One of the largest non-nuclear explosions in history occurred along the Trans-Siberian Pipeline in the former Soviet Union. It has been alleged that the explosion was the result of CIA sabotage of the Trans-Siberian Pipeline. June 4, 1989 - sparks from two passing trains detonated gas leaking from an LPG pipeline near Ufa, Russia. Up to 645 people were reported killed. October 17, 1998 - 1998 Jesse pipeline explosion at Jesse in the Niger Delta in Nigeria, a petroleum pipeline exploded killing about 1,200 villagers, some of whom were scavenging gasoline - the worst of several similar incidents in this country. June 10, 1999 - a pipeline rupture in a Bellingham, Washington park led to the release of 277,200 gallons of gasoline. The gasoline was ignited, causing an explosion that killed two children and one adult. Misoperation of the pipeline and a previously damaged section of the pipe that was not detected before were identified as causing the failure.[26] August 19, 2000 - natural gas pipeline rupture and fire near Carlsbad, New Mexico; this explosion and fire killed 12 members of an extended family. The cause was due to severe internal corrosion of the pipeline.[27] July 30, 2004 - a major natural gas pipeline exploded in Ghislenghien, Belgium near Ath (thirty kilometres southwest of Brussels), killing at least 24 people and leaving 132 wounded, some critically. (Expatica) May 12, 2006 - an oil pipeline ruptured outside Lagos, Nigeria. Up to 200 people may have been killed. See Nigeria oil blast. November 1, 2007 - a propane pipeline exploded near Carmichael, Mississippi, about 30 miles (48 km) south of Meridian, Mississippi. Two people were killed instantly and an additional four were injured. Several homes were destroyed and sixty families were displaced. The pipeline is owned by Enterprise Products Partners LP, and runs from Mont Belvieu, Texas, to Apex, North Carolina. Inability to find flaws in pre-1971 ERW seam welded pipe flaws was a contributing factor to the accident.[28][29] September 9, 2010 - a 30 inch diameter high pressure natural gas pipeline owned by Pacific Gas & Electric exploded in flames in the Crestmoor residential neighborhood 2 mi (3.2 km) west of San Francisco International Airport, killing 8, injuring 58, and destroying 38 homes. Poor quality control of the pipe used & of the construction were cited as factors in the accident.[30]
[edit] As targets
Pipelines can be the target of vandalism, sabotage, or even terrorist attacks. In war, pipelines are often the target of military attacks, as destruction of pipelines can seriously disrupt enemy logistics.
Oil refinery From Wikipedia, the free encyclopedia Jump to: navigation, search
Anacortes Refinery (Tesoro), on the north end of March Point southeast of Anacortes, Washington
An oil refinery or petroleum refinery is an industrial process plant where crude oil is processed and refined into more useful products such as petroleum naphtha, gasoline, diesel fuel, asphalt base, heating oil, kerosene, and liquefied petroleum gas.[1][2] Oil refineries are typically large, sprawling industrial complexes with extensive piping running throughout, carrying streams of fluids between large chemical processing units. In many ways, oil refineries use much of the technology of, and can be thought of, as types of chemical plants. The crude oil feedstock has typically been processed by an oil production plant. There is usually an oil depot (tank farm) at or near an oil refinery for the storage of incoming crude oil feedstock as well as bulk liquid products.
An oil refinery is considered an essential part of the downstream side of the petroleum industry.Contents [hide] 1 Operation 2 Major products 3 Common process units found in a refinery 3.1 Flow diagram of typical refinery 3.2 The crude oil distillation unit
4 Specialty end products 5 Siting/locating of petroleum refineries 6 Safety and environmental concerns 7 Corrosion problems and prevention 8 History 8.1 Oil refining in the United States 9 See also 10 References 11 External links
[edit] Operation
Crude oil is separated into fractions by fractional distillation. The fractions at the top of the fractionating column have lower boiling points than the fractions at the bottom. The heavy bottom fractions are often cracked into lighter, more useful products. All of the fractions are processed further in other refining units.
Raw or unprocessed crude oil is not generally useful in industrial applications, although "light, sweet" (low viscosity, low sulfur) crude oil has been used directly as a burner fuel for steam vessel propulsion. The lighter elements, however, form explosive vapors in the fuel tanks and are therefore hazardous, especially in warships. Instead, the hundreds of different hydrocarbon molecules in crude oil are separated in a refinery into components which can be used as fuels, lubricants, and as feedstock in petrochemical processes that manufacture such products as plastics, detergents, solvents, elastomers and fibers such as nylon and polyesters.
Petroleum fossil fuels are burned in internal combustion engines to provide power for ships, automobiles, aircraft engines, lawn mowers, chainsaws, and other machines. Different boiling points allow the hydrocarbons to be separated by distillation. Since the lighter liquid products are in great demand for use in internal combustion engines, a modern refinery will convert heavy hydrocarbons and lighter gaseous elements into these higher value products.
The oil refinery in Haifa, Israel is capable of processing about 9 million tons (66 million barrels) of crude oil a year. Its two cooling towers are landmarks of the city's skyline.
Oil can be used in a variety of ways because it contains hydrocarbons of varying molecular masses, forms and lengths such as paraffins, aromatics, naphthenes (or cycloalkanes), alkenes, dienes, and alkynes. While the molecules in crude oil include different atoms such as sulfur and nitrogen, the hydrocarbons are the most common form of molecules, which are molecules of varying lengths and complexity made of hydrogen and carbon atoms, and a small number of oxygen atoms. The differences in the structure of these molecules account for their varying physical and chemical properties, and it is this variety that makes crude oil useful in a broad range of applications.
Once separated and purified of any contaminants and impurities, the fuel or lubricant can be sold without further processing. Smaller molecules such as isobutane and propylene or butylenes can be recombined to meet specific octane requirements by processes such as alkylation, or less commonly, dimerization. Octane grade of gasoline can also be improved by catalytic reforming, which involves removing hydrogen from hydrocarbons producing compounds with higher octane ratings such as aromatics. Intermediate products such as gasoils can even be reprocessed to break a heavy, long-chained oil into a lighter short-chained one, by various forms of cracking such as fluid catalytic cracking, thermal cracking, and hydrocracking. The final step in gasoline production is the blending of fuels with different octane ratings, vapor pressures, and other properties to meet product specifications.
Oil refineries are large scale plants, processing about a hundred thousand to several hundred thousand barrels of crude oil a day. Because of the high capacity, many of the units operate continuously, as opposed to processing in batches, at steady state or nearly steady state for months to years. The high capacity also makes process optimization and advanced process control very desirable. [edit] Major products
Petroleum products are usually grouped into three categories: light distillates (LPG, gasoline, naphtha), middle distillates (kerosene, diesel), heavy distillates and residuum (heavy fuel oil, lubricating oils, wax, asphalt). This classification is based on the way crude oil is distilled and separated into fractions (called distillates and residuum) as in the above drawing.[2]
Liquified petroleum gas (LPG) Gasoline (also known as petrol) Naphtha Kerosene and related jet aircraft fuels Diesel fuel Fuel oils Lubricating oils Paraffin wax Asphalt and tar Petroleum coke Sulfur
Oil refineries also produce various intermediate products such as hydrogen, light hydrocarbons, reformate and pyrolysis gasoline. These are not usually transported but instead are blended or processed further on-site. Chemical plants are thus often adjacent to oil refineries. For example, light hydrocarbons are steam-cracked in an ethylene plant, and the produced ethylene is polymerized to produce polyethene. [edit] Common process units found in a refinery
Storage tanks and towers at Shell Puget Sound Refinery (Shell Oil Company), Anacortes, Washington Desalter unit washes out salt from the crude oil before it enters the atmospheric distillation unit. Atmospheric distillation unit distills crude oil into fractions. See Continuous distillation. Vacuum distillation unit further distills residual bottoms after atmospheric distillation. Naphtha hydrotreater unit uses hydrogen to desulfurize naphtha from atmospheric distillation. Must hydrotreat the naphtha before sending to a Catalytic Reformer unit.
Catalytic reformer unit is used to convert the naphtha-boiling range molecules into higher octane reformate (reformer product). The reformate has higher content of aromatics and cyclic hydrocarbons). An important byproduct of a reformer is hydrogen released during the catalyst reaction. The hydrogen is used either in the hydrotreaters or the hydrocracker. Distillate hydrotreater unit desulfurizes distillates (such as diesel) after atmospheric distillation. Fluid catalytic cracker (FCC) unit upgrades heavier fractions into lighter, more valuable products. Hydrocracker unit uses hydrogen to upgrade heavier fractions into lighter, more valuable products. Visbreaking unit upgrades heavy residual oils by thermally cracking them into lighter, more valuable reduced viscosity products. Merox unit treats LPG, kerosene or jet fuel by oxidizing mercaptans to organic disulfides. Alternative processes for removing mercaptans are known, e.g. doctor sweetening process and caustic washing. Coking units (delayed coking, fluid coker, and flexicoker) process very heavy residual oils into gasoline and diesel fuel, leaving petroleum coke as a residual product. Alkylation unit produces high-octane component for gasoline blending. Dimerization unit converts olefins into higher-octane gasoline blending components. For example, butenes can be dimerized into isooctene which may subsequently be hydrogenated to form isooctane. There are also other uses for dimerization. Isomerization unit converts linear molecules to higher-octane branched molecules for blending into gasoline or feed to alkylation units. Steam reforming unit produces hydrogen for the hydrotreaters or hydrocracker. Liquified gas storage vessels store propane and similar gaseous fuels at pressure sufficient to maintain them in liquid form. These are usually spherical vessels or "bullets" (i.e., horizontal vessels with rounded ends). Storage tanks store crude oil and finished products, usually cylindrical, with some sort of vapor emission control and surrounded by an earthen berm to contain spills. Amine gas treater, Claus unit, and tail gas treatment convert hydrogen sulfide from hydrodesulfurization into elemental sulfur. Utility units such as cooling towers circulate cooling water, boiler plants generates steam, and instrument air systems include pneumatically operated control valves and an electrical substation.
Wastewater collection and treating systems consist of API separators, dissolved air flotation (DAF) units and further treatment units such as an activated sludge biotreater to make water suitable for reuse or for disposal.[3] Solvent refining units use solvent such as cresol or furfural to remove unwanted, mainly aromatics from lubricating oil stock or diesel stock. Solvent dewaxing units remove the heavy waxy constituents petrolatum from vacuum distillation products. [edit] Flow diagram of typical refinery
The image below is a schematic flow diagram of a typical oil refinery that depicts the various unit processes and the flow of intermediate product streams that occurs between the inlet crude oil feedstock and the final end products. The diagram depicts only one of the literally hundreds of different oil refinery configurations. The diagram also does not include any of the usual refinery facilities providing utilities such as steam, cooling water, and electric power as well as storage tanks for crude oil feedstock and for intermediate products and end products.[1][4][5][6]
Schematic flow diagram of a typical oil refinery
There are many process configurations other than that depicted above. For example, the vacuum distillation unit may also produce fractions that can be refined into endproducts such as: spindle oil used in the textile industry, light machinery oil, motor oil, and various waxes. [edit] The crude oil distillation unit
The crude oil distillation unit (CDU) is the first processing unit in virtually all petroleum refineries. The CDU distills the incoming crude oil into various fractions of different boiling ranges, each of which are then processed further in the other refinery processing units. The CDU is often referred to as the atmospheric distillation unit because it operates at slightly above atmospheric pressure.[1][2][7]
Below is a schematic flow diagram of a typical crude oil distillation unit. The incoming crude oil is preheated by exchanging heat with some of the hot, distilled fractions and other streams. It is then desalted to remove inorganic salts (primarily sodium chloride).
Following the desalter, the crude oil is further heated by exchanging heat with some of the hot, distilled fractions and other streams. It is then heated in a fuel-fired furnace (fired heater) to a temperature of about 398 °C and routed into the bottom of the distillation unit.
The cooling and condensing of the distillation tower overhead is provided partially by exchanging heat with the incoming crude oil and partially by either an air-cooled or water-cooled condenser. Additional heat is removed from the distillation column by a pumparound system as shown in the diagram below.
As shown in the flow diagram, the overhead distillate fraction from the distillation column is naphtha. The fractions removed from the side of the distillation column at various points between the column top and bottom are called sidecuts. Each of the sidecuts (i.e., the kerosene, light gas oil and heavy gas oil) is cooled by exchanging heat with the incoming crude oil. All of the fractions (i.e., the overhead naphtha, the sidecuts and the bottom residue) are sent to intermediate storage tanks before being processed further.
Schematic flow diagram of a typical crude oil distillation unit as used in petroleum crude oil refineries. [edit] Specialty end products
These require blending various feedstocks, mixing appropriate additives, providing short term storage, and preparation for bulk loading to trucks, barges, product ships, and railcars: Gaseous fuels such as propane, stored and shipped in liquid form under pressure in specialized railcars to distributors. Lubricants (produces light machine oils, motor oils, and greases, adding viscosity stabilizers as required), usually shipped in bulk to an offsite packaging plant.
Wax (paraffin), used in the packaging of frozen foods, among others. May be shipped in bulk to a site to prepare as packaged blocks. Sulfur (or sulfuric acid), byproducts of sulfur removal from petroleum which may have up to a couple percent sulfur as organic sulfur-containing compounds. Sulfur and sulfuric acid are useful industrial materials. Sulfuric acid is usually prepared and shipped as the acid precursor oleum. Bulk tar shipping for offsite unit packaging for use in tar-and-gravel roofing. Asphalt unit. Prepares bulk asphalt for shipment. Petroleum coke, used in specialty carbon products or as solid fuel. Petrochemicals or petrochemical feedstocks, which are often sent to petrochemical plants for further processing in a variety of ways. The petrochemicals may be olefins or their precursors, or various types of aromatic petrochemicals. [edit] Siting/locating of petroleum refineries
A party searching for a site to construct a refinery or a chemical plant needs to consider the following issues: The site has to be reasonably far from residential areas. Infrastructure should be available for supply of raw materials and shipment of products to markets. Energy to operate the plant should be available. Facilities should be available for waste disposal.
Refineries which use a large amount of steam and cooling water need to have an abundant source of water. Oil refineries therefore are often located nearby navigable rivers or on a sea shore, nearby a port. Such location also gives access to transportation by river or by sea. The advantages of transporting crude oil by pipeline are evident, and oil companies often transport a large volume of fuel to distribution terminals by pipeline. Pipeline may not be practical for products with small output, and rail cars, road tankers, and barges are used.
Petrochemical plants and solvent manufacturing (fine fractionating) plants need spaces for further processing of a large volume of refinery products for further processing, or to mix chemical additives with a product at source rather than at blending terminals. [edit] Safety and environmental concerns
Fire-extinguishing operations after the Texas City refinery explosion.
The refining process releases a number of different chemicals into the atmosphere (see AP 42 Compilation of Air Pollutant Emission Factors) and a notable odor normally accompanies the presence of a refinery. Aside from air pollution impacts there are also wastewater concerns,[3] risks of industrial accidents such as fire and explosion, and noise health effects due to industrial noise.
Many governments worldwide have mandated restrictions on contaminants that refineries release, and most refineries have installed the equipment needed to comply with the requirements of the pertinent environmental protection regulatory agencies. In the United States, there is strong pressure to prevent the development of new refineries, and no major refinery has been built in the country since Marathon's Garyville, Louisiana facility in 1976. However, many existing refineries have been expanded during that time. Environmental restrictions and pressure to prevent construction of new refineries may have also contributed to rising fuel prices in the United States.[8] Additionally, many refineries (over 100 since the 1980s) have closed due to obsolescence and/or merger activity within the industry itself.
Environmental and safety concerns mean that oil refineries are sometimes located some distance away from major urban areas. Nevertheless, there are many instances where refinery operations are close to populated areas and pose health risks such as in the Campo de Gibraltar, a CEPSA refinery near the towns of Gibraltar, Algeciras, La Linea, San Roque and Los Barrios with a combined population of over 300,000 residents within a 5-mile (8.0 km) radius and the CEPSA refinery in Santa Cruz on the island of Tenerife, Spain[9] which is sited in a densely populated city center and next to the only two major evacuation routes in and out of the city. In California's Contra Costa County and Solano County, a shoreline necklace of refineries, built in the early 20th century before this area was populated, and associated chemical plants are adjacent to urban areas in Richmond, Martinez, Pacheco, Concord, Pittsburg, Vallejo and Benicia, with occasional accidental events that require "shelter in place" orders to the adjacent populations.
[edit] Corrosion problems and prevention
Petroleum refineries run as efficiently as possible to reduce costs. One major factor that decreases efficiency is corrosion of the metallic components found throughout refining process. Corrosion causes the failure of equipment items as well as dictating the maintenance schedule of the refinery, during which part or all of the refinery must be shut down. The corrosion-related direct costs in the U.S. petroleum industry as of 1996 was estimated as US$3.7 billion per year.[10][11]
Corrosion occurs in various forms in the refining process, such as pitting corrosion from water droplets, embrittlement from hydrogen, and stress corrosion cracking from sulfide attack.[12] From a materials standpoint, carbon steel is used for upwards of 80 per cent of refinery components, which is beneficial due to its low cost. Carbon steel is resistant to the most common forms of corrosion, particularly from hydrocarbon impurities at temperatures below 205 °C, but other corrosive chemicals and environments prevent its use everywhere. Common replacement materials are low alloy steels containing chromium and molybdenum, with stainless steels containing more chromium dealing with more corrosive environments. More expensive materials commonly used are nickel, titanium, and copper alloys. These are primarily saved for the most problematic areas where extremely high temperatures or very corrosive chemicals are present.[13]
Corrosion is fought by a complex system of monitoring, preventative repairs and careful use of materials. Monitoring methods include both off-line checks taken during maintenance and on-line monitoring. Off-line checks measure corrosion after it has occurred, telling the engineer when equipment must be replaced based on the historical information he has collected. This is referred to as preventative management.
On-line systems are a more modern development, and are revolutionizing the way corrosion is approached. There are several types of on-line corrosion monitoring technologies such as linear polarization resistance, electrochemical noise and electrical resistance. On-Line monitoring has generally had slow reporting rates in the past (minutes or hours) and been limited by process conditions and sources of error but newer technologies can report rates up to twice per minute with much higher accuracy (referred to as real-time monitoring). This allows process engineers to treat corrosion as another process variable that can be optimized in the system. Immediate responses to process changes allow the control of corrosion mechanisms, so they can be minimized while also maximizing production output.[14] In an ideal situation having on-line
corrosion information that is accurate and real-time will allow conditions that cause high corrosion rates to be identified and reduced. This is known as predictive management.
Materials methods include selecting the proper material for the application. In areas of minimal corrosion, cheap materials are preferable, but when bad corrosion can occur, more expensive but longer lasting materials should be used. Other materials methods come in the form of protective barriers between corrosive substances and the equipment metals. These can be either a lining of refractory material such as standard Portland cement or other special acid-resistant cements that are shot onto the inner surface of the vessel. Also available are thin overlays of more expensive metals that protect cheaper metal against corrosion without requiring lots of material.[15] [edit] History
The first oil refinery in the world was built in 1851 at Bathgate, Scotland, by Scottish chemist James Young*16+ shortly followed by Ignacy Łukasiewicz near Jasło, Poland from 1854 to 1856,[17][18] but they were initially small as there was no real demand for refined fuel. As Łukasiewicz's kerosene lamp gained popularity, the refining industry grew in the area.
The world's first large refinery opened at Ploiești, Romania, in 1856-1857,[19] with United States investment. After being taken over by Nazi Germany, the Ploiești refineries were bombed in Operation Tidal Wave by the Allies during the Oil Campaign of World War II. Another early large refinery is Oljeön, Sweden (1875) (Swedish name means The Petroleum Isle), now preserved as a museum near Engelsberg Ironworks, a UNESCO World Heritage Site, and part of the Ekomuseum Bergslagen.[20]
At one point, the refinery in Ras Tanura, Saudi Arabia owned by Saudi Aramco was claimed to be the largest oil refinery in the world. For most of the 20th century, the largest refinery was the Abadan Refinery in Iran. This refinery suffered extensive damage during the Iran-Iraq war. The world's largest refinery complex is the Jamnagar Refinery Complex, consisting of two refineries side by side operated by Reliance Industries Limited in Jamnagar, India with a combined production capacity of 1,240,000 barrels per day (197,000 m3/d) (J-1 660,000 bbl/d (105,000 m3/d), J-2 580,000 bbl/d (92,000 m3/d). PDVSA's Paraguana refinery complex in Venezuela with a capacity of 956,000 bbl/d (152,000 m3/d) and SK Energy's Ulsan in South Korea with 840,000 bbl/d (134,000 m3/d) are the second and third largest, respectively.[when?] [edit]
Oil refining in the United States
In the 19th century, refineries in the U.S. processed crude oil primarily to recover the kerosene. There was no market for the more volatile fraction, including gasoline, which was considered waste and was often dumped directly into the nearest river. The invention of the automobile shifted the demand to gasoline and diesel, which remain the primary refined products today. Today, national and state legislation requires refineries to meet stringent air and water cleanliness standards. In fact, oil companies in the U.S. perceive obtaining a permit to build a modern refinery to be so difficult and costly that no new refineries have been built (though many have been expanded) in the U.S. since 1976. More than half the refineries that existed in 1981 are now closed due to low utilization rates and accelerating mergers.[21] As a result of these closures total US refinery capacity fell between 1981 to 1995, though the operating capacity stayed fairly constant in that time period at around 15,000,000 barrels per day (2,400,000 m3/d).[22] Increases in facility size and improvements in efficiencies have offset much of the lost physical capacity of the industry. In 1982 (the earliest data provided), the United States operated 301 refineries with a combined capacity of 17.9 million barrels (2,850,000 m3) of crude oil each calendar day. In 2010, there were 149 operable U.S. refineries with a combined capacity of 17.6 million barrels (2,800,000 m3) per calendar day.[23]
In 2009 through 2010, as revenue streams in the oil business dried up and profitability of oil refineries fell due to lower demand for product and high reserves of supply preceding the economic recession, oil companies began to close or sell refineries. [edit] See also
Gas compressor From Wikipedia, the free encyclopedia Jump to: navigation, search
A small stationary high pressure breathing air compressor for filling scuba cylinders
A gas compressor is a mechanical device that increases the pressure of a gas by reducing its volume.
Compressors are similar to pumps: both increase the pressure on a fluid and both can transport the fluid through a pipe. As gases are compressible, the compressor also reduces the volume of a gas. Liquids are relatively incompressible; while some can be compressed, the main action of a pump is to pressurize and transport liquids.Contents [hide] 1 Types of compressors 1.1 Hermetically sealed, open, or semi-hermetic 1.2 Centrifugal compressors 1.3 Diagonal or mixed-flow compressors 1.4 Axial-flow compressors 1.5 Reciprocating compressors 1.6 Rotary screw compressors 1.7 Rotary vane compressors 1.8 Scroll compressors 1.9 Diaphragm compressors 1.10 Air bubble compressor 2 Temperature 3 Staged compression 4 Prime movers 5 Applications 6 See also 7 References
[edit] Types of compressors
The main types of gas compressors are illustrated and discussed below:
[edit] Hermetically sealed, open, or semi-hermetic
A small hermetically sealed compressor in a common consumer refrigerator or freezer typically has a rounded steel outer shell permanently welded shut, which seals operating gases inside the system. There is no route for gases to leak, such as around motor shaft seals. On this model, the plastic top section is part of an auto-defrost system that uses motor heat to evaporate the water.
Compressors are often described as being either open, hermetic, or semi-hermetic, to describe how the compressor and motor drive is situated in relation to the gas or vapour being compressed. The industry name for a hermetic is hermetically sealed compressor, while a semihermetic is commonly called a semi-hermetic compressor.
In hermetic and most semi-hermetic compressors, the compressor and motor driving the compressor are integrated, and operate within the pressurized gas envelope of the system. The motor is designed to operate and be cooled by the gas or vapour being compressed.
The difference between the hermetic and semi-hermetic, is that the hermetic uses a onepiece welded steel casing that cannot be opened for repair; if the hermetic fails it is simply replaced with an entire new unit. A semi-hermetic uses a large cast metal shell with gasketed covers that can be opened to replace motor and pump components.
The primary advantage of a hermetic and semi-hermetic is that there is no route for the gas to leak out of the system. Open compressors rely on either natural leather or synthetic rubber seals to retain the internal pressure, and these seals require a lubricant such as oil to retain their sealing properties.
An open pressurized system such as an automobile air conditioner can leak its operating gases, if it is not operated frequently enough. Open systems rely on lubricant in the system to splash on pump components and seals. If it is not operated frequently enough, the lubricant on the seals slowly evaporates, and then the seals begin to leak until the system is no longer functional and must be recharged. By comparison, a hermetic system can sit unused for years, and can usually be started up again at any time without requiring maintenance or experiencing any loss of system pressure.
The disadvantage of hermetic compressors is that the motor drive cannot be repaired or maintained, and the entire compressor must be removed if a motor fails. A further disadvantage is that burnt out windings can contaminate whole systems requiring the system to be entirely pumped down and the gas replaced. Typically hermetic compressors are used in low-cost factoryassembled consumer goods where the cost of repair is high compared to the value of the device, and it would be more economical to just purchase a new device.
An advantage of open compressors is that they can be driven by non-electric power sources, such as an internal combustion engine or turbine. However, open compressors that drive refrigeration systems are generally not totally maintenance free throughout the life of the system, since some gas leakage will occur over time. [edit] Centrifugal compressors
Figure 1: A single stage centrifugal compressor Main article: Centrifugal compressor
Centrifugal compressors use a rotating disk or impeller in a shaped housing to force the gas to the rim of the impeller, increasing the velocity of the gas. A diffuser (divergent duct) section converts the velocity energy to pressure energy. They are primarily used for continuous, stationary service in industries such as oil refineries, chemical and petrochemical plants and natural gas processing plants.[1][2][3] Their application can be from 100 horsepower (75 kW) to thousands of horsepower. With multiple staging, they can achieve extremely high output pressures greater than 10,000 psi (69 MPa).
Many large snowmaking operations (like ski resorts) use this type of compressor. They are also used in internal combustion engines as superchargers and turbochargers. Centrifugal compressors are used in small gas turbine engines or as the final compression stage of medium sized gas turbines. Sometimes the capacity of the compressors is written in NM3/hr. Here 'N' stands for normal temperature pressure (20°C and 1 atm ) for example 5500 NM3/hr. [edit] Diagonal or mixed-flow compressors Main article: Diagonal or mixed-flow compressor
Diagonal or mixed-flow compressors are similar to centrifugal compressors, but have a radial and axial velocity component at the exit from the rotor. The diffuser is often used to turn diagonal flow to an axial rather than radial direction. [edit] Axial-flow compressors
An animation of an axial compressor. Main article: Axial-flow compressor
Axial-flow compressors are dynamic rotating compressors that use arrays of fan-like airfoils to progressively compress the working fluid. They are used where there is a requirement for a high flow rate or a compact design.
The arrays of airfoils are set in rows, usually as pairs: one rotating and one stationary. The rotating airfoils, also known as blades or rotors, accelerate the fluid. The stationary airfoils, also known as stators or vanes, decelerate and redirect the flow direction of the fluid, preparing it for the rotor blades of the next stage.[1] Axial compressors are almost always multi-staged, with the cross-sectional area of the gas passage diminishing along the compressor to maintain an optimum axial Mach number. Beyond about 5 stages or a 4:1 design pressure ratio, variable geometry is normally used to improve operation.
Axial compressors can have high efficiencies; around 90% polytropic at their design conditions. However, they are relatively expensive, requiring a large number of components, tight tolerances and high quality materials. Axial-flow compressors can be found in medium to large gas turbine engines, in natural gas pumping stations, and within certain chemical plants. [edit] Reciprocating compressors Main article: Reciprocating compressor
A motor-driven six-cylinder reciprocating compressor that can operate with two, four or six cylinders.
Reciprocating compressors use pistons driven by a crankshaft. They can be either stationary or portable, can be single or multi-staged, and can be driven by electric motors or internal combustion engines.[1][4][5] Small reciprocating compressors from 5 to 30 horsepower (hp) are commonly seen in automotive applications and are typically for intermittent duty. Larger reciprocating compressors well over 1,000 hp (750 kW) are commonly found in large industrial and petroleum applications. Discharge pressures can range from low pressure to very high pressure (>18000 psi or 180 MPa). In certain applications, such as air compression, multi-stage doubleacting compressors are said to be the most efficient compressors available, and are typically larger, and more costly than comparable rotary units.[6] Another type of reciprocating compressor is the swash plate compressor, which uses pistons moved by a swash plate mounted on a shaft (see axial piston pump.
Household, home workshop, and smaller job site compressors are typically reciprocating compressors 1½ hp or less with an attached receiver tank. [edit] Rotary screw compressors
Diagram of a rotary screw compressor Main article: Rotary screw compressor
Rotary screw compressors use two meshed rotating positive-displacement helical screws to force the gas into a smaller space.[1][7][8] These are usually used for continuous operation in commercial and industrial applications and may be either stationary or portable. Their application can be from 3 horsepower (2.2 kW) to over 1,200 horsepower (890 kW) and from low pressure to moderately high pressure (>1,200 psi or 8.3 MPa).
Rotary screw compressors are commercially produced in Oil Flooded, Water Flooded and Dry type. [edit] Rotary vane compressors See also: Rotary vane pump
Rotary vane compressors consist of a rotor with a number of blades inserted in radial slots in the rotor. The rotor is mounted offset in a larger housing that is either circular or a more complex shape. As the rotor turns, blades slide in and out of the slots keeping contact with the outer wall of the housing.[1] Thus, a series of decreasing volumes is created by the rotating blades. Rotary Vane compressors are, with piston compressors one of the oldest of compressor technologies.
With suitable port connections, the devices may be either a compressor or a vacuum pump. They can be either stationary or portable, can be single or multi-staged, and can be driven by electric motors or internal combustion engines. Dry vane machines are used at relatively low pressures (e.g., 2 bar or 200 kPa; 29 psi) for bulk material movement while oil-injected machines have the necessary volumetric efficiency to achieve pressures up to about 13 bar (1,300 kPa; 190 psi) in a single stage. A rotary vane compressor is well suited to electric motor drive and is significantly quieter in operation than the equivalent piston compressor.
Rotary vane compressors can have mechanical efficiencies of about 90%.[9] [edit] Scroll compressors
Mechanism of a scroll pump
Main article: Scroll compressor
A scroll compressor, also known as scroll pump and scroll vacuum pump, uses two interleaved spiral-like vanes to pump or compress fluids such as liquids and gases. The vane geometry may be involute, archimedean spiral, or hybrid curves.[10][11][12] They operate more smoothly, quietly, and reliably than other types of compressors in the lower volume range.
Often, one of the scrolls is fixed, while the other orbits eccentrically without rotating, thereby trapping and pumping or compressing pockets of fluid or gas between the scrolls.
This type of compressor was used as the supercharger on Volkswagen G60 and G40 engines in the early 1990s. [edit] Diaphragm compressors Main article: Diaphragm compressor
A diaphragm compressor (also known as a membrane compressor) is a variant of the conventional reciprocating compressor. The compression of gas occurs by the movement of a flexible membrane, instead of an intake element. The back and forth movement of the membrane is driven by a rod and a crankshaft mechanism. Only the membrane and the compressor box come in contact with the gas being compressed.[1]
The degree of flexing and the material constituting the diaphragm affects the maintenance life of the equipment. Generally stiff metal diaphragms may only displace a few cubic centimeters of volume because the metal can not endure large degrees of flexing without cracking, but the stiffness of a metal diaphragm allows it to pump at high pressures. Rubber or silicone diaphragms are capable of enduring deep pumping strokes of very high flexion, but their low strength limits their use to low-pressure applications, and they need to be replaced as plastic embrittlement occurs.
Diaphragm compressors are used for hydrogen and compressed natural gas (CNG) as well as in a number of other applications.
A three-stage diaphragm compressor
The photograph included in this section depicts a three-stage diaphragm compressor used to compress hydrogen gas to 6,000 psi (41 MPa) for use in a prototype compressed hydrogen and compressed natural gas (CNG) fueling station built in downtown Phoenix, Arizona by the Arizona Public Service company (an electric utilities company). Reciprocating compressors were used to compress the natural gas.
The prototype alternative fueling station was built in compliance with all of the prevailing safety, environmental and building codes in Phoenix to demonstrate that such fueling stations could be built in urban areas. [edit] Air bubble compressor
Also known as a trompe. A mixture of air and water generated through turbulence is allowed to fall into a subterranean chamber where the air separates from the water. The weight of falling water compresses the air in the top of the chamber. A submerged outlet from the chamber allows water to flow to the surface at a lower height than the intake. An outlet in the roof of the chamber supplies the compressed air to the surface. A facility on this principal was built on the Montreal River at Ragged Shutes near Cobalt, Ontario in 1910 and supplied 5,000 horsepower to nearby mines.[13] [edit] Temperature Main article: Gas laws
Compression of a gas naturally increases its temperature, often referred to as the heat of compression.
where
so
in which p is pressure, V is volume, n takes different values for different compression processes (see below), and 1 & 2 refer to initial and final states. Adiabatic - This model assumes that no energy (heat) is transferred to or from the gas during the compression, and all supplied work is added to the internal energy of the gas, resulting in increases of temperature and pressure. Theoretical temperature rise is[14]:
with T1 and T2 in degrees Rankine or kelvins, p2 and p1 being absolute pressures and k = ratio of specific heats (approximately 1.4 for air). The rise in air and temperature ratio means compression does not follow a simple pressure to volume ratio. This is less efficient, but quick. Adiabatic compression or expansion more closely model real life when a compressor has good insulation, a large gas volume, or a short time scale (i.e., a high power level). In practice there will always be a certain amount of heat flow out of the compressed gas. Thus, making a perfect adiabatic compressor would require perfect heat insulation of all parts of the machine. For example, even a bicycle tire pump's metal tube becomes hot as you compress the air to fill a tire. The relation between temperature and compression ratio described above means that the value of n for an adiabatic process is k (the ratio of specific heats). Isothermal - This model assumes that the compressed gas remains at a constant temperature throughout the compression or expansion process. In this cycle, internal energy is removed from the system as heat at the same rate that it is added by the mechanical work of compression. Isothermal compression or expansion more closely models real life when the compressor has a large heat exchanging surface, a small gas volume, or a long time scale (i.e., a small power level). Compressors that utilize inter-stage cooling between compression stages come closest to achieving perfect isothermal compression. However, with practical devices perfect isothermal compression is not attainable. For example, unless you have an infinite number of compression stages with corresponding intercoolers, you will never achieve perfect isothermal compression.
For an isothermal process, n is 1, so the value of the work integral for an isothermal process is:
When evaluated, the isothermal work is found to be lower than the adiabatic work. Polytropic - This model takes into account both a rise in temperature in the gas as well as some loss of energy (heat) to the compressor's components. This assumes that heat may enter or leave the system, and that input shaft work can appear as both increased pressure (usually useful work) and increased temperature above adiabatic (usually losses due to cycle efficiency). Compression efficiency is then the ratio of temperature rise at theoretical 100 percent (adiabatic) vs. actual (polytropic). Polytropic compression will use a value of n between 0 (a constant-pressure process) and infinity (a constant volume process). For the typical case where an effort is made to cool the gas compressed by an approximately adiabatic process, the value of n will be between 1 and k. [edit] Staged compression
In the case of centrifugal compressors, commercial designs currently do not exceed a compression ratio of more than a 3.5 to 1 in any one stage (for a typical gas). Since compression generates heat, the compressed gas is to be cooled between stages making the compression less adiabatic and more isothermal. The inter-stage coolers typically result in some partial condensation that is removed in vapor-liquid separators.
In the case of small reciprocating compressors, the compressor flywheel may drive a cooling fan that directs ambient air across the intercooler of a two or more stage compressor.
Because rotary screw compressors can make use of cooling lubricant to remove the heat of compression, they very often exceed a 9 to 1 compression ratio. For instance, in a typical diving compressor the air is compressed in three stages. If each stage has a compression ratio of 7 to 1, the compressor can output 343 times atmospheric pressure (7 × 7 × 7 = 343 atmospheres). (343 atm or 34.8 MPa; 5.04 ksi) [edit] Prime movers
There are many options for the "prime mover" or motor that powers the compressor: Gas turbines power the axial and centrifugal flow compressors that are part of jet engines. Steam turbines or water turbines are possible for large compressors. Electric motors are cheap and quiet for static compressors. Small motors suitable for domestic electrical supplies use single phase alternating current. Larger motors can only be used where an industrial electrical three phase alternating current supply is available. Diesel engines or petrol engines are suitable for portable compressors and support compressors. Common in automobiles and other types of vehicles (including piston-powered airplanes, boats, trucks, etc.), diesel or gasoline engines can power compressors using their own crankshaft power (this setup known as a supercharger), or, using their waste exhaust gas to spin a turbine connected to the compressor (this setup known as a turbocharger). [edit] Applications
Gas compressors are used in various applications where either higher pressures or lower volumes of gas are needed: In pipeline transport of purified natural gas from the production site to the consumer, a compressor is driven by a gas turbine fueled by gas bled from the pipeline. Thus, no external power source is necessary. Petroleum refineries, natural gas processing plants, petrochemical and chemical plants, and similar large industrial plants require compressing for intermediate and end-product gases. Refrigeration and air conditioner equipment use compressors to move heat in refrigerant cycles (see vapor-compression refrigeration). Gas turbine systems compress the intake combustion air. Small-volume purified or manufactured gases require compression to fill high pressure cylinders for medical, welding, and other uses. Various industrial, manufacturing, and building processes require compressed air to power pneumatic tools. Some aircraft require compressors to maintain cabin pressurization at altitude.
Some types of jet engines—such as turbojets and turbofans)—compress the air required for fuel combustion. The jet engine's turbines power the combustion air compressor. in SCUBA diving, hyperbaric oxygen therapy, and other life support devices, compressors put breathing gas into small volume containers, such as diving cylinders.[15][16] In surface supplied diving, an air compressor frequently supplies low pressure air (10 to 20 bar) for breathing. Submarines use compressors to store air for later use in displacing water from buoyancy chambers to adjust depth. Turbochargers and superchargers are compressors that increase internal combustion engine performance by increasing the mass flow of air inside the cylinder, so the engine can burn more fuel and hence produce more power. rail and heavy road transport vehicles use compressed air to operate rail vehicle or road vehicle brakes—and various other systems (doors, windscreen wipers, engine, gearbox control, etc.). Service stations and auto repair shops use compressed air to fill pneumatic tires and power pneumatic tools. Fire pistons and heat pumps exist to heat air or other gasses, and compressing the gas is only a means to that end.
Overview
Nigeria has a population of over 110 million people and an abundance of natural resources, especially hydrocarbons. It is the 10th largest oil producer in the world, the third largest in Africa and the most prolific oil producer in Sub-Saharan Africa. The Nigerian economy is largely dependent on its oil sector which supplies 95% of its foreign exchange earnings.
The upstream oil industry is Nigeria’s lifeblood and yet it is also central to the ongoing civil unrest in the country, which gained worldwide publicity with the trial and execution of Ken Saro Wiwa, and eight other political activists in 1995.
The upstream oil industry is the single most important sector in the economy. According to the 2012 BP Statistical Energy Survey, Nigeria had proved oil reserves of 37.2 billion barrels at the end of 2011, equivalent to 41.4 years of current production and 2.25 % of the world's reserves while the country produced an average of 2457.3 thousand barrels of crude oil per day in 2011, 2.93% of the world and a change of 0.1 % compared to 2010.
Most of this is produced from the prolific Niger River Delta. Despite problems associated with ethnic unrest, border disputes and government funding, Nigeria’s wealth of oil makes it most attractive to the major oil-multinationals, most of whom are represented in Nigeria, with the major foreign stakeholder being Shell. Nigeria produced an average of 2401.6 thousand barrels of crude oil per day in 2010, 2.94% of the world and a change of 16.2 % compared to 2009.
According to the 2011 BP Statistical Energy Survey, Nigeria had 2010 proved natural gas reserves of 5.29 trillion cubic metres, 2.82% of the world . Due, mainly, to the lack of a gas infrastructure, 75% of associated gas is flared and 12% re-injected. Nigeria has set a target of zero flare by 2010 and is providing incentives for the production and use of gas. The government also plans to raise earnings from natural gas exports to 50 percent of oil revenues by 2010. It has been reported in the 2011 BP Statistical Energy Survey that Nigeria had 2010 natural gas production of 33.63 billion cubic metres, a change of 35.6% versus 2009 and equivalent to 1.05% of the world total.
Nigeria's downstream oil industry is also a key sector including four refineries with a nameplate capacity of 438,750 bbl/d. Problems such as fire, sabotage, poor management, lack of turn around maintenance and corruption have meant that the refineries often operate at 40% of full capacity, if at all. This has resulted in shortages of refined product and the need to increase imports to meet domestic demand. Nigeria has a robust petrochemicals industry based on its substantial refining capacity and natural gas resources. The petrochemical industry is focussed around the three centres of Kaduna, Warri and Eleme.
Until 1960, government participation in the oil industry was limited to the regulation and administration of fiscal policies. In 1971, Nigeria joined OPEC and in line with OPEC resolutions, the Nigerian National Oil Corporation (NNOC) was established, later becoming NNPC in 1977. This giant parastatal, with all its subsidiary companies, controls and dominates all sectors of the oil industry, both upstream and downstream.
In April 2000, the Nigerian government set up a new committee on oil and gas reform to deal with the deregulation and privatisation of NNPC. Seven subsidiaries of NNPC are due to be sold including the three refineries, the Eleme Petrochemicals Company Ltd, the Nigerian Petroleum Development Company and the partially owned oil marketing firm, Hyson Nigeria Ltd.
Nigeria is a member of OPEC and is its 12th largest producer. The former SecretaryGeneral of OPEC, Dr Rilwanu Lukman, is a Nigerian national and Petroleum Advisor to the President.
The petroleum industry in Nigeria is regulated by the Ministry of Petroleum Resources. The government retains close control over the industry and the activities of the NNPC, whose senior executives are appointed by the ruling government. :: Update Upstream
The upstream oil industry is the single most important sector in the country's economy, providing over 90% of its total exports.
Oil is produced from five of Nigeria’s seven sedimentary basins: the Niger Delta, Anambra, Benue Trough, Chad, and Benin. The Niger Delta, the Onshore and Shallow Offshore basins can be considered fairly well to well explored. Ventures here are low risk and the basins contain about 80% of producing wells drilled in Nigeria. During the later 1990s exploration focus turned to high risk ventures in the frontier basins of the deep water offshore with encouraging success. These ventures are becoming increasingly attractive with developments in deepwater exploration and production technology.
Nigeria is a member of OPEC. Its crude oils have a gravity between 21·API and 45·API. Its main export crudes are Bonny Light (37·) and Forcados (31·). About 65% of Nigeria’s oil is above 35·API with a very low sulphur content. Nigeria’s OPEC quota is 1.89 million bbl/d. :: Update Downstream
The downstream oil industry in Nigeria is another key sector in the country's economy. The country has four oil refineries and There are eight oil companies and 750 independents all active in the marketing petroleum products. Cross-border smuggling is an ongoing problem and there are frequent reports of large scale corruption in the distribution and marketing chain. The government through its 100% state-owned national oil company, Nigerian National Petroleum Corporation (NNPC) has had an all encompassing control over the industry through its shareholding in all the companies involved and in the setting of wholesale and retail prices. :: Update Risks
There are risks associated with investment in Nigeria. These can be grouped into three main categories, political activity and civil unrest, border disputes and government underfunding. There is also the continuing problem of corruption within the system.
Political activity and civil unrest.
The issue at the basis of most civil unrest is the equitable sharing of the country’s annual oil revenues among its population and the question of the environmental responsibilities of the oil multinationals. Although all multinationals have been targeted in the disputes, Shell has been the main target. Civil unrest has resulted in over 700 deaths since Obasanjo’s take over and resulted in the shut in of terminals and flow stations. The situation is exacerbated by corruption within the industry and the government. Abasanjo has committed his government to resolving the problems and cleaning up the industry and the government in terms of corruption. Border disputes
In the complex boundary delimitations of the Niger Delta area, border disputes are common. Nigeria is currently in dispute with both Cameroon and Equatorial Guinea over borders relating to oil finds in the Gulf of Guinea. Cameroon and Nigeria each claim the Bakassi Peninsula located in the Gulf of Guinea and which is believed to contain significant reserves of oil. In February 1994, Cameroon submitted the dispute to the International Court of Justice (ICJ) for settlement, and Nigeria later followed with its own suit to the ICJ. The ICJ began formal hearings in March 1998 but no decision had been reached by mid 1999.
Nigeria is in dispute over Equatorial Guinea’s sole ownership of the Zafiro oilfield in Block B from which Mobil began producing in 1996. Elf holds the concession OML 102 in Nigeria, just 3.5km north of Equatorial Guinea’s Block B. Nigeria and Elf contend that the seismic evidence indicates that Zafiro is part of an oilfield that straddles the international boundary between the two countries. In 1998, Elf announced the Ekanga discovery based on two wells drilled in OML 102. Equatorial Guinea claims that the wells were drilled in their territorial waters in Block B. Nigeria has called for a determination of the boundary and the establishment of a joint field operation. Negotiations have met with little success so far. Government underfunding
A recurring problem in the upstream sector is the inability of the NNPC to meet its funding obligations to the JVs. Under JV terms, the NNPC shares costs with its foreign partners. Since 1993, budgetary constraints on the NNPC have resulted in it being unable to meet its JV commitments leading to cut backs in exploration and production. The government is seeking to diversify funding for the industry and alternative funding schemes have been approved for Shell’s EA project and are being considered for Elf’s development of the Amenam field.
Pigging in the context of pipelines refers to the practice of using pipeline inspection gauges or 'pigs' to perform various maintenance operations on a pipeline. This is done without stopping the flow of the product in the pipeline.
These operations include but are not limited to cleaning and inspecting of the pipeline. This is accomplished by inserting the pig into a 'pig launcher' (or 'launching station') - a funnel shaped Y section in the pipeline. The launcher / launching station is then closed and the pressure-driven flow of the product in the pipeline is used to push it along down the pipe until it reaches the receiving trap – the 'pig catcher' (or receiving station).
If the pipeline contains butterfly valves, or reduced port ball valves, the pipeline cannot be pigged. Full port (or full bore) ball valves cause no problems because the inside diameter of the ball is the same as that of the pipe.
Pigging has been used for many years to clean larger diameter pipelines in the oil industry. Today, however, the use of smaller diameter pigging systems is now increasing in many continuous and batch process plants as plant operators search for increased efficiencies and reduced costs.
Pigging can be used for almost any section of the transfer process between, for example, blending, storage or filling systems. Pigging systems are already installed in industries handling products as diverse as lubricating oils, paints, chemicals, toiletries, cosmetics and foodstuffs.
Pigs are used in lube oil or painting blending: they are used to clean the pipes to avoid crosscontamination, and to empty the pipes into the product tanks (or sometimes to send a component back to its tank). Usually pigging is done at the beginning and at the end of each batch, but sometimes it is done in the midst of a batch, e.g. when producing a premix that will be used as an intermediate component.
Pigs are also used in oil and gas pipelines: they are used to clean the pipes but there are also "smart pigs" used to measure things like pipe thickness and corrosion along the pipeline. They usually do not interrupt production, though some product can be lost when the pig is extracted. They can also be used to separate different products in a multiproduct pipeline.Contents [hide] 1 Etymology 2 Pigging in production environments 2.1 Product and time saving 2.2 Environmental issues 2.3 Safety considerations 2.4 Intelligent pigging 3 Pipeline Inspection Gauge 4 In popular culture 5 See also 6 References 7 External links
[edit] Etymology
The original pigs were made from straw wrapped in wire used for cleaning. They made a squealing noise while traveling through the pipe, sounding to some like a pig squealing, which gave pigs the name.[1][2] (Disputed: 'PIG' is an acronym or backronym derived from the initial letters of the term 'Pipeline Inspection Gauge.').[citation needed] [edit] Pigging in production environments [edit] Product and time saving
A major advantage of piggable systems is the potential resulting product savings. At the end of each product transfer, it is possible to clear out the entire line contents with the pig, either forwards towards the receipt point, or backwards to the source tank. There is no requirement for extensive line flushing.
Without the need for line flushing, pigging offers the additional advantage of a much more rapid and reliable product changeover. Product sampling at the receipt point becomes faster because the interface between products is very clear, and the old method of checking at intervals, until the product is on-specification, is considerably shortened.
Pigging can also be operated totally by a programmable logic controller (PLC). [edit] Environmental issues
Pigging has a significant role to play in reducing the environmental impact of batch operations. Traditionally, the only way that an operator of a batch process could ensure a product was completely cleared from a line was to flush the line with a cleaning agent such as water or a
solvent or even the next product. This cleaning agent then had to be subjected to effluent treatment or solvent recovery. If product was used to clear the line, the contaminated finished product was downgraded or dumped. All of these problems can now be eliminated due to the very precise interface produced by modern pigging systems. [edit] Safety considerations
Pigging systems are designed so that the pig is loaded into the launcher, which is pressured up to launch the pig into the pipeline through a kicker line. In some cases, the pig is removed from the pipeline via the receiver at the end of each run.[3] All systems must allow for the receipt of pigs at the launcher, as blockages in the pipeline may require the pigs to be pushed back to the launcher. Most of the time, systems are designed to pig the pipeline in either direction.
The pig is pushed either with an inert gas or a liquid; if pushed by gas, some systems[4] can be adapted in the gas inlet in order to ensure pig's constant speed, whatever the pressure drop is. The pigs must be removed, as many pigs are rented, pigs wear and must be replaced, and cleaning pigs push contaminants from the pipeline such as wax, foreign objects, hydrates, etc., which must be removed from the pipeline. There are inherent risks in opening the barrel to atmosphere and care must be taken to ensure that the barrel is depressured prior to opening. If the barrel is not completely depressured, the pig can be ejected from the barrel and operators have been severely injured when standing in front of an open pig door. One pig was shot out of the end of a pipeline without a proper pig receiver by accident, and went through the side of a home 500 feet away.[5] When the product is sour, the barrel should be evacuated to a flare system where the sour gas is burnt. Operators should be wearing a self-contained breathing apparatus when working on sour systems.
A few pigging systems utilize a "captive pig", and the pipeline is only opened up very occasionally to check the condition of the pig.[6] At all other times, the pig is shuttled up and down the pipeline at the end of each transfer, and the pipeline itself is never opened up during process operation. These systems are not common. [edit] Intelligent pigging
Inserting a pig into a natural gas pipeline
Modern intelligent pigs are highly sophisticated instruments that vary in technology and complexity by the intended use and by manufacturer. An intelligent pig, or smart pig, includes electronics and sensors that collects various forms of data during the trip through the pipeline.
The electronics are sealed to prevent leakage of the pipeline product into the electronics since products can range from highly basic to highly acidic and can be of extremely high temperature. Many pigs use specific materials according to the product in the pipeline. Power for the electronics is provided by onboard batteries which are also sealed. Data recording may be by various means ranging from analog tape, digital tape, or solid state memory in more modern digital units.
The technology used to accomplish the service varies by the service required and the design of the pig, each pigging service provider may have unique and proprietary technologies to accomplish the service. Surface pitting and corrosion, as well as cracks and weld defects in steel/ferrous pipelines are often detected using magnetic flux leakage (MFL) pigs. Other "smart" pigs use electromagnetic acoustic transducers to detect pipe defects. Caliper pigs can measure the roundness of the pipeline to determine areas of crushing or other deformations. Some smart pigs can combine technologies such as MFL and Caliper into a single tool. Trials of pigs using acoustic resonance technology have been reported.[7]
During the pigging run the pig is unable to directly communicate with the outside world due to the distance underground or underwater and/or materials that the pipe is made of. For example, steel pipelines effectively prevent any reliable radio communications outside the pipe. It is therefore necessary that the pig use internal means to record its own movement during the trip. This may be done by gyroscope-assisted tilt sensors, odometers and other technologies.[8] The pig will record this positional data so that the distance it moves along with any bends can be interpreted later to determine the exact path taken.
Location verification is often accomplished by surface instruments that record the pig’s passage by either audible, magnetic, or gravimetric[citation needed] (or other) means. The sensors will record when they detect passage of the pig (time-of-arrival); this is then compared to the internal record for verification or adjustment. The external sensors may have GPS capability[9] to assist in their location. A few pig passage indicators transmit the pig’s passage, time and location, via Orbcomm satellite uplink.[10] The pig itself cannot use GPS as the metal pipe blocks satellite signals.
After the pigging run has been completed, the positional data from the external sensors is combined with the pipeline evaluation data (corrosion, cracks, etc.) from the pig to provide a location-specific defect map and characterization. In other words, the combined data will tell the operator the location and type and size of each pipe defect. This is used to judge the severity of the defect and help repair crews locate and repair the defect quickly without having to dig up excessive amounts of pipeline. By evaluating the rate of change of a particular defect over several years, proactive plans can be made to repair the pipeline before any leakage or environmental damage occurs.
The inspection results are typically archived (perhaps in Pipeline Open Data Standard format) for comparison with the results of later pigging runs on the same pipeline. [edit] Pipeline Inspection Gauge
A pig on display in a section of cutaway pipe, from the Alaska Pipeline
A "Pig" launcher/receiver, belonging to the natural gas pipeline in Switzerland.
A pipeline inspection gauge or "PIG" in the pipeline industry is a tool that is sent down a pipeline and propelled by the pressure of the product in the pipeline itself. There are four main uses for pigs: Physical separation between different liquids being transported in pipelines; Internal cleaning of pipelines; Inspection of the condition of pipeline walls (also known as an Inline Inspection (ILI) tool); Capturing and recording geometric information relating to pipelines (e.g. size, position).
One kind of pig is a soft, bullet shaped polyurethane foam plug that is forced through pipelines to separate products to reduce mixing. There are several types of pigs for cleaning. Some have tungsten studs or abrasive wire mesh on the outside to cut rust, scale, or paraffin deposits off the inside of the pipe. Others are plain plastic covered polyurethane.
Inline inspection pigs use various methods for inspecting a pipeline. A sizing pig uses one (or more) notched round metal plates that are used as gauges. The notches allow different parts of the plate to bend when a bore restriction is encountered. More complex systems exist for inspecting various aspects of the pipeline. Intelligent pigs, also called smart pigs, are used to inspect the pipeline with sensors and record the data for later analysis. These pigs use technologies such as MFL and ultrasonics to inspect the pipeline. Intelligent pigs may also use calipers to measure the inside geometry of the pipeline.
In 1961, the first intelligent pig was run by Shell Development. It demonstrated that a selfcontained electronic instrument could traverse a pipe line while measuring and recording wall thickness. The instrument used electromagnetic fields to sense wall integrity. In 1964 Tuboscope ran the first commercial instrument. It used MFL technology to inspect the bottom portion of the pipeline. The system used a black box similar to those used on aircraft to record the information, basically a highly customized analog tape recorder. Until recently, tape recording (although digital) was still the preferred recording medium. As the capacity and reliability of solid-state memory improved, most recording media moved away from tape to solid state.
Capacitive sensor probes are used in the process of detecting defects in polyethylene pipe gas pipeline. These probes are attached to the pig in which the pig is sent through the polyethylene pipe that will detect any defects in the outside of the pipe wall. This is done by using a triple plate capacitive sensor in which the electrostatic waves are propagated outward through the pipe's wall. Any change in dielectric material will result in a change in capacitance.[11] Testing was conducted by NETL DOE research lab at the Battelle West Jefferson’s Pipeline Simulation Facility (PSF) near Columbus, Ohio.[12]
A
Abandoned Well A well that is not in use because it was drilled as a dry hole or has ceased to produce or for some other reason cannot be operated. (In Canada, Talisman continues to make excellent progress against reclamation and abandonment obligations. The Company spent approximately $7.5 million on site cleanup in Canada in 2001.)
Aggregator Sometimes referred to as MARKETERS. An independent corporation that buys natural gas from many producers, re-sells it to buyers, and obtains the necessary pipeline transportation capacity and removal/export permits and licences. Aggregators usually sell to buyers that individually require large amounts of natural gas, such as local distribution companies and large industrial customers.
Appraisal Wells Wells generally drilled in the vicinity of a discovery or wildcat well for the purpose of evaluating the extent and the importance of the find.
Associated Gas Gas that is produced from the same reservoir in association with crude oil, either as free gas or in solution.
Back To Top B
Barrel Petroleum industry standard barrel. Equals 0.159 m3.
Bitumen Petroleum that exists in the semi-solid or solid phase in natural deposits.
Blowout An uncontrolled flow of gas, oil or other liquids from a well.
Blowout Preventer (BOP) Equipment that is installed at the wellhead to control pressures and fluids during drilling, completion, workovers and other remedial operations.
British Thermal Unit (Btu) The amount of heat required to raise the temperature of one pound of water one degree Fahrenheit at or near 39.2F
Back To Top C
Carbon Dioxide (CO2) An inert non-toxic gas produced from decaying materials, respiration of plant and animal life, and combustion of organic matter, including fossil fuels. For many years, this gas had little commercial value except for the production of dry ice but, in recent years, it has become a valuable resource employed in tertiary oil recovery projects.
Carbonate A sediment formed from the hard parts of marine organisms mainly consisting of calcite, aragonite and dolomite. Rocks formed from such sediments are important oil and gas reservoirs throughout the world.
Casing A type of pipe that is used for encasing a smaller diameter carrier pipe for installation in a well. Casing is used to send off fluids from the hole or keep a hole from caving in.
Coal Bed Methane (CBM) Natural gas generated and trapped in coal seams.
Coiled Tubing A continuous, jointless hollow steel cylinder that is stored on a reel and can be uncoiled or coiled repeatedly as required; coiled tubing is increasingly being used in well completion and servicing instead of traditional tubing, which is made up of joined sections of pipe.
Completed Well A well where operations have advanced to a stage where it is ready to produce oil or gas.
Compressed Natural Gas (CNG) Natural gas that has been highly compressed and is stored in high-pressure surface containers. CNG is used as a transportation fuel for automobiles, trucks and buses.
Compressor Station A facility in which the pressure of natural gas is raised to facilitate its transmission through pipelines.
Condensate Hydrocarbons liquids of high API gravity, usually produced in association with natural gas and which are liquid at normal pressure and temperature.
Conventional Crude Oil Petroleum found in liquid form either flowing naturally from its reservoir or capable of being pumped.
Core A continuous cylinder of rock, usually from five to 10 centimetres in diameter, cut from the bottom of a well-bore. Cores are cut during the drilling of a well and are used in the study of underground formations.
Corporate Governance Balance of powers between boards of directors, senior management, shareholders and stakeholders of companies.
Corporate Responsibility or CR Defined by the World Business Council for Sustainable Development as the continuing commitment by business to behave ethically and contribute to economic development while improving the quality of life of the workforce and their families as well as the local community and society at large.
Crown Land Mineral rights owned by the federal or provincial governments in Canada.
Cubic Foot The volume of gas that fills one cubic foot of space under standard temperature and pressure conditions. Standard pressure is 14.73 psi and standard temperature is 60F.
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Decommissioning Taking out of use, ready for dismantling/removal.
Deep Basin Gas Natural gas that is found at depths greater than the average for a particular area.
Deliverability The amount of natural gas a well, field, pool, gathering, transmission or distribution system can supply in a given period of time.
Density The weight of crude oil, indicating the proportion of large, carbon-rich molecules, generally measured in kilograms per cubic metre (kg/m3) or degrees on the American Petroleum Institute (API) gravity scale; in Western Canada, oil up to 900 kg/m3 is considered light to medium crude – oil above this density is deemed as heavy oil or bitumen.
Development Well A well generally drilled in or adjacent to a proven part of a pool to optimize petroleum production.
Directional (deviated) Well A well drilled at an angle from the vertical by using a slanted drilling rig or by deflecting the drillbit. Directional wells can be used to drill multiple wells from a common drilling pad or to reach a subsurface location beneath land where drilling cannot be done.
Discovery Well An exploratory well that results in the discovery of a new gas or oilfield or pool.
Downstream A term used most commonly in the petroleum industry to describe post production processes (e.g. refining and marketing sectors of the petroleum industry).
Drill Pipe
The heavy steel pipe used to rotate the drill bit and circulate drilling mud. Drill pipe is generally in sections, approximately 9 metres long, are screwed together to form a continuous pipe and extend from the drilling rig to the drilling bit at the bottom of the hole. Rotation of the drill pipe and bit causes the bit to bore through the rock.
Drill String The column or "string" made up of connected drill pipe. The drill string carries the mud down to, and rotates, the drillbit.
Drilling Mud Fluid circulated down the drill pipe and up the annulus during drilling operations to remove cuttings, cool and lubricate the bit and maintain a desired pressure in the well.
Drillstem Test A method of sampling fluid from a formation by isolating an interval in the wellbore, using a tool attached to the drill string (or “drill stem”). The sample is used to assess the type and volume of fluids in the formation as well as their pressure and rate of flow.
Dry Gas Natural gas that does not contain dissolved liquid hydrocarbons.
Dry Hole An unsuccessful well, a well not capable of producing commercial quantities of oil or gas.
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End-User A person or company who actually consumes natural gas (as opposed to one who sells or resells it).
Enhanced Oil Recovery (EOR) Any method that increases oil production by using techniques or materials that are not part of normal pressure maintenance or water flooding operations. Examples include oil recovered through the injection of gas or miscible fluids.
Environmental Audit Systematic, documented verification process of objectively obtaining and evaluating audit evidence to determine whether specified environmental activities, events, conditions, management systems or information about these matters conform with audit criteria.
Environmental Impact Assessment A set of activities designed to contribute pertinent environmental information to project or program decision-making.
Established Reserves Those reserves recoverable under current technology and present and anticipated economic conditions. Also a term commonly used in reference to total proved reserves plus half probable reserves.
Exploration The act of searching for potential sub-surface reservoirs of gas or oil. Methods include the use of magnetometers, gravity meters, seismic exploration, surface mapping, and the drilling of exploratory test wells (wildcats).
Exploratory Well
A well drilled either in search of new and yet undiscovered accumulations of oil and gas, or in an attempt to significantly extend the limits of a known reservoir.
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Farmout An arrangement whereby the owner of a lease assigns all or some portion of the lease or licences to another company for undertaking exploration or development activity.
Field The geographical area encompassing a group of one or more underground hydrocarbon pools that share the same or related infrastructure.
Field Pressure The pressure of the natural gas as it is found in the underground formations from which it is produced.
Fish Any object left in the wellbore during drilling or workover operations that must be recovered or drilled around before work can proceed.
Formation A designated mapable sub-surface layer that is composed of substantially the same kind of rock or rock types.
Fracturing (or fracing)
A process of opening up "channels" in an underground hydrocarbon reservoir by pumping special fluids down the well under high pressure. Fracturing causes the formation to crack open, creating passages for the reservoir fluids to more easily flow into the wellbore.
Futures Market Market trading in contracts to buy and sell a particular commodity at a fixed price on a certain date.
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Gas Cap Free gas on top of the oil zone in an underground reservoir.
Gas in Place (GIP) The volume of gas in a reservoir at any given time, calculated at standard temperature and pressure conditions, that includes both recoverable and non-recoverable gas.
Gas Pool The term "gas pool" is generally synonymous with the term "gas reservoir".
Gas Processing Plant A facility which performs one of the following: removing water or moisture from the gas stream (i.e. dehydration), removing liquefiable hydrocarbons from wetgas or casinghead gas (i.e.. gas processing), removing undesirable gaseous and particulate elements from natural gas (i.e. gas treatment).
Gas Reservoir Rock that forms a trap for the accumulation of and natural gas and associated liquids.
Gathering System A system of pipelines, compressor stations and any other related facilities that gather natural gas from a supply region and transports it to the major transmission systems. Generally, pipelines in gathering systems are smaller in diameter and operate at lower pressures (field-gathering systems), although some gathering systems (e.g. the NOVA system in Alberta) also have lines that are comparable to those found in transmission systems.
Geologist A person trained in the study of the Earth’s crust. Petroleum geologists search for traps (structural or stratigraphic) favourable for the accumulation of hydrocarbons and determine favourable locations for drilling.
Geophysical Survey The accurate measurement and recording of certain physical quantities of the Earth’s crust geophysical methods (e.g. seismic) to locate probable reservoir structures capable of producing commercial quantities of natural gas and/or crude oil.
Geophysics The science that deals with the study of the Earth by quantitative physical methods and relations between the physical features of the Earth and forces that produce them; geophysics includes the study of seismology and magnetism.
Global Compact An initiative by Kofi Annan, Secretary General of the United Nations, to engage the private sector in helping address common issues of environmental protection, human rights and labour.
Global Reporting Initiative
A multi-stakeholder process and independent institution whose mission is to develop and disseminate globally applicable sustainability reporting guidelines.
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Heavy Oil A dense, viscous oil with a high proportion of bitumen, which is difficult to extract with conventional techniques and is more costly to refine.
Horizontal Drilling Drilling a well that deviates from the vertical and travels horizontally through a prospective reservoir.
Hydrocarbons An organic chemical compound of hydrogen and carbon. Hydrocarbons are a large class of liquid, solid or gaseous organic compounds, that are the basis of almost all petroleum products.
Hydrogen Sulphide (H2S) A naturally occurring, highly toxic gas with the odour of rotten eggs, commonly found in association with natural gas.
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Infill Drilling Additional wells drilled between established producing wells on a lease in order to increase production from the reservoir.
Injection Well A well employed for injecting air, steam or fluids into an underground formation.
In-situ In its original place or position. In-situ recovery refers to various methods used to recover deeply buried bitumen deposits, including steam injection, solvent injection and firefloods.
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Kyoto Protocol The Kyoto Protocol to the UN Framework Convention on Climate Change (UNFCCC) was adopted in Kyoto on December 11, 1997. It contains quantified greenhouse gas (GHG) emission limitation and reduction commitments, expressed in CO2 equivalent, for signatory countries.
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Landman An employee of an oil company whose primary duties are formulating and carrying out exploration strategies and managing an oil company’s relations with its landowners and partners, including securing and administering oil and gas leases and other agreements.
Lease A formal agreement between two or more parties where the owner of the land grants another party the right to drill and produce petroleum substances in exchange for payment.
Light Crude Oil Liquid petroleum characterized by low density that flows freely at room temperature.
Liquefied Natural Gas (LNG) Natural gas that has been supercooled to about 160C for storage as a liquid. LNG occupies 1/640th of its original volume and is, therefore, easier to transport if pipelines cannot be used.
Lost-Time Injuries Injuries that result in workers being unable to report to their next work shift.
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Medium Crude Oil
Liquid petroleum with a density between that of light and heavy crude oil.
Midstream Activity involving the processing, storage and transportation sectors of the petroleum industry.
Mineral Rights Represents the legal rights to explore for and produce the resources below the surface. In the petroleum industry, mineral rights can also be referred to as "land."
Miscible Flooding An oil-recovery technique or process in which a fluid, capable of mixing completely with the oil it contacts, is injected into an oil reservoir to increase recovery.
Mud Usually a colloidal suspension of clays in water along with chemical additives that is circulated through the wellbore during rotary drilling.
Multi-Zone Well Completion Completion of a well such that production is obtained from several different formations.
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National Energy Board (NEB)
A federal regulatory agency in Canada that sets tolls and tariffs for oil and gas pipelines under federal jurisdiction; authorizes oil, natural gas and electricity exports and certifies interprovincial and international pipelines, and designated interprovincial and international power lines.
Natural Gas Liquids (NGLs) Hydrocarbon liquids obtained during natural gas production and processing; they include ethane, propane, butane and condensate.
Non-Associated Gas A reservoir where only gas is found (i.e. crude oil is not present).
Non-Government Organizations (NGOs) Groups with mutual interests and objectives that are non-profit and independent of government.
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Oil Sands A deposit of sand saturated with bitumen. Canada has some of the largest oil sands deposits in the world (Athabasca tar sands).
Operator Company appointed by the co-venturers in a licence to manage the exploration for and, if successful, the production of oil/gas on behalf of the co-venturers.
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Pay Zone The producing portion of a formation.
Permeability The capacity of a reservoir rock to transmit fluids (i.e. a measure of how easily fluids can pass through the rock).
Petrochemicals Chemicals derived from petroleum and used as feedstocks for the manufacture of a variety of plastics and other products, such as synthetic rubber.
Petroleum A naturally occurring complex mixture composed predominantly of hydrocarbons in a gaseous, liquid or solid phase.
Pipeline All parts of a physical facility through which gas is transported, including pipe, valves, and other appendages attached to the pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.
Pool A natural underground reservoir containing an accumulation of petroleum.
Porosity
Volume of space within a rock that might contain hydrocarbons (like the amount of water a sponge can hold). Represents the open or void space within rock – usually expressed as a percentage of the total rock volume. Porosity measures the capacity of the rock to hold natural gas, crude oil or water.
Precambrian Formed prior to the Cambrian era (older than approximately 600 million years ago).
Probable Reserves Hydrocarbon deposits believed to exist with a reasonable certainty on the basis of geological information.
Production Carbon Intensity The mass of carbon dioxide emissions emitted during the production of each unit of oil and gas. The GHG potentials of other greenhouse gases are included in the calculation.
Production Energy Intensity Energy consumed in the production of each unit of oil and gas.
Prospect A geographical area that exploration has shown contains sedimentary rocks and structures that may be favourable for the presence of crude oil or natural gas.
Proved Reserves Hydrocarbons in known reservoirs that can be recovered with a great degree of certainty under existing technological and economic conditions. Proved reserves represent the category of natural gas reserves that have the highest probability of being produced. Generally, these reserves have been “proved” to exist with drilling evidence. Every authority has a slightly different definition of the exact parameters which define proved reserves.
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Raw Natural Gas A mixture containing methane plus all or some of the following: ethane, propane, butane, pentanes, condensates, nitrogen, carbon dioxide, hydrogen sulfide, helium, hydrogen, water vapour and minor impurities. Raw natural gas is the gas found naturally in the ground prior to processing. During processing, the volume decreases as impurities and liquids are removed.
Reclamation The process of converting lands disturbed by oil and gas activities to other productive land uses, involving reshaping areas to a stable configuration, establishment of drainage systems, placement of topsoil or plant growth media and revegetation through planting or seeding.
Recoverable Resources Total hydrocarbon that can be produced with current technology, including those not economical to produce at present and those not tied into existing production facilities.
Reservoir (pool)
A porous, permeable underground rock formation containing a discrete natural accumulation of crude oil or natural gas, confined by impermeable rock or water barriers, and separate from other reservoirs.
Royalty The share of production or revenues retained by government or freehold mineral rights holders.
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Sandstone A compacted sedimentary rock most commonly composed of quartz or feldspar. Sandstones are a common rock in which oil, natural gas and/or water accumulate.
Secondary Recovery Extraction of incremental crude oil, natural gas and related substances from reservoirs through pressure maintenance techniques, such as waterflooding and gas injection.
Sedimentary Rocks One of three basic forms of rocks (the other two being igneous and metamorphic) formed by the accumulation of sediment or organic materials. Sedimentary rocks are likely to contain hydrocarbons. Sedimentary rocks generally form from matter deposited by streams, lakes, seas or other bodies of water.
Seismic Surveys Studies done to gather and record the patterns of induced shock wave reflections from underground layers of rock. Seismic surveys are used to create detailed models of the underlying geological structure used in the exploration and development of hydrocarbons.
Service Rig A rig (often truck-mounted), usually smaller than a drilling rig, that is brought in to complete a well or to perform maintenance, replace equipment or improve production.
Set Casing The installation of steel pipe or casing in a wellbore. An accompanying operation is the cementing of the casing in place by surrounding it with a wall of cement extending for all or a portion of the depth of the well.
Shale A sedimentary rock formed from the deposition of clay.
Shut-in Gas Well A producing well that has been closed down temporarily for repair, clean out, workover, lack of market, etc.
Sour Gas Natural gas contaminated with chemical impurities (commonly CO2 or H2S).
Spot Market A market characterized by short-term contracts for specified volumes of gas. Spot market participants may be producers, marketers, brokers, LDCs or end-users.
Spud (a well) The first or initial act of boring of the hole in drilling of an oil or gas well.
Steam Injection A thermal recovery method representing improved recovery technique in which steam is injected into a reservoir to reduce the viscosity of the crude oil.
Step Out A well drilled adjacent to a proven well but located in an unproven area. May represent a well located as a "step out" from proven territory in an effort to determine the boundaries of a producing formation.
Sulphur A yellow-coloured, natural element commonly extracted from petroleum and used for making fertilizers, pharmaceuticals and other products.
Sulphur Dioxide (SO2) A highly toxic gas formed by burning hydrogen sulphide.
Surface Casing The first string of casing put into a well. Surface casing is cemented into bedrock and serves to shut out shallow water formations and as a foundation for well control during drilling operations.
Surface Rights The legal rights to work on the surface of the land.
Sweet Gas Raw natural gas characterized by a relatively low concentration of sour compounds, such as hydrogen sulfide and carbon dioxide.
Synthetic Crude Oil
A mixture of hydrocarbons, similar to crude oil, derived by upgrading bitumen extracted from oil sands.
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Tertiary Recovery The third major phase of crude oil recovery and that involves using more sophisticated techniques, such as steam-flooding or injection of chemicals, to increase recovery.
Tripping The process of removing the drill string from the hole to change the bit and running the drill string and new bit back into the hole.
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Upstream The sector of the petroleum industry involving exploration and production.
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Viscosity
The measure of resistance to flow or "stickiness" of a fluid.
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Wellbore A hole drilled or bored into the earth and usually cased with metal pipe for the production of gas or oil.
Wellhead Equipment used to maintain surface control of a well.
Western Canada Sedimentary Basin (WCSB) Canada’s largest region of sedimentary rocks; the largest source of current oil and gas production. The WCSB covers a large area of Manitoba, Saskatchewan, Alberta and the Northwest Territories.
Wildcat A well drilled in an area where no oil or gas production exists nearby.
Working Interest The interest in a mineral property that entitles the owner to a portion of the production from the property. A working interest may entitle the owner to royalty payments.
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Back To Top ABBREVIATIONSAPI
American Petroleum Institute
bbls
Barrels
bbls/d
Barrels per day
bcf
Billion cubic feet
boe
Barrels of oil equivalent
boe/d
Barrels of oil equivalent per day
CAA
Commercial Agreement Area
CAGR
Compound Annual Growth Rate
CAPP
Canadian Association of Petroleum Producers
C$
Canadian dollars
CO2E
Carbon dioxide equivalent
DBRS
Dominion Bond Rating Service
EBITDAX Earnings before interest, preferred security charges, income taxes, depreciation, depletion and amortization, impairment write downs, exploration and dry hole expense EU
European Union
FPSO
Floating, Production, Storage and Offloading Vessel
FSO
Floating, Storage and Offloading Vessel
GJ
109joules or a billion joules
GT
109tonnes or a billion tonnes
m3
Cubic metres
mboe/d
Thousand barrels of oil equivalent per day
mcf
Thousand cubic feet
mcf/d
Thousand cubic feet per day
MW
106watts or a million watts
mg/L
Milligram per litre
mmboe
Million barrels of oil equivalent
mmbtu
Million British thermal units
mmcf
Million cubic feet
mmcf/d
Million cubic feet per day
Moody's
Moody's Investor Service
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
OECD
Organization of Economic Cooperation and Development
OPEC
Organization of Petroleum Exporting Countries
PSC
Production Sharing Contract
ppm
Parts per million
S&P
Standard & Poor's Ratings Group
tcf
Trillion cubic feet
TSX
Toronto Stock Exchange
UDHR
Universal Declaration of Human Rights
UK
United Kingdom
UN
United Nations
US
United States
US$
United States dollars
WTI
West Texas Intermediate
₤
Pound sterling
Absorption is a process used by older gas processing plants and in many refinery gas plants to remove natural gas liquids from natural gas. The gas is run through oil of a proper character that absorbs the liquid components of the gas. This process is not as efficient as cryogenic processing and only 70% propane and all of the butane and natural gasoline are recovered.
Acoustic logs record sound waves through the rocks and indicates the rock's porosity.
In an Acreage Contribution Agreement the contributing party agrees to contribute leases or interests in the area of the test well to the drilling party in exchange for information, if a well is drilled to an agreed depth.
Alkylation is a refinery process in which butylene or propylene is combined with isobutane to form an iso-paraffin. The process is used to improve the octane quality. The resulting alkylate is a valuable gasoline blending component.
The American Petroleum Institute (API) is the trade organization representing the largest US oil and gas companies. The API defines tests to measure various hydrocarbon qualities.
Ammonia is a colorless, nonflammable and liquefied gas with a strong smell (NH3); is easily liquefied by compression or by cooling to about -33° C (-27.4° F). In returning to the gaseous state, it absorbs substantial amounts of heat from its surroundings (i.e., one gram of ammonia absorbs 327 calories of heat). Because of this property, it is frequently employed as a coolant in refrigerating and air-conditioning equipment; used in the manufacture of urea and other fertilizers.
Anticline is a subsurface geological structure in the form of a sine curve or an elongated dome. The formation is favorable to the accumulation of oil and /or gas.
Anticline Traps are formed when the rock layers have been folded upward to form a dome. The trap looks like an inverted bowl with the upper layer of seal rock holding the fluids in the reservoir rock in place.
API gravity is a measure of the specific gravity of the petroleum fraction relative to water. API gravity bears a relationship to true specific gravity but is more convenient to work with than the decimal fractions that would result if petroleum were expressed in specific gravity.
Aquifers are water reservoirs that are conditioned to hold the gas. Natural gas must be brought in to "condition" the site and it takes four years before the site can be used.
Aromatics are a group of hydrocarbon fractions that form the basis of most organic chemicals so far synthesized. The name 'aromatics' is derived from their rather pleasant odor. The unique ring structure of their carbon atoms makes it possible to transform aromatics into an almost endless number of chemicals.
Artificial lift is a way of bringing oil to the surface when the reservoir pressure has declined. The method involves pumping oil well with a rod, tubing, or bottom-hole centrifugal pump.
Asphalt is a solid hydrocarbon that is dark brown or black in color. Asphalt may be found as as a deposit, but is more typically produced from vacuum residua in the refinery.
Auto-refrigeration is the process in which LNG is kept at its boiling point, so that any added heat is countered by energy lost from boil off.
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Basins are natural depressions in the earth's surface, in which sediments have accumulated over millions of years. Sedimentary basins are regarded as good prospects for oil and gas exploration.
Batch is a measured amount of crude oil or refined products in a pipeline or storage tank.
Benzene (C6H6) is a colorless liquid hydrocarbon made from coal tar. Used in the manufacture of styrene, nylon, detergents and other compounds, it is also a component of high-octane gasoline.
Blending is a process of mixing two or more petroleum fractions to produce a finished refined product that satisfies the product specifications.
Boil off is the LNG that evaporates during storage and transport. Typically, any rise rise in temperature of LNG during storage and transport will be countered by allowing evaporated LNG to vent from storage tank. Boil off gas is sometimes used to supplement fuel for tankers, or as a fuel at storage facilities.
Bonus is the money paid by the lessee for the execution of an oil and gas lease by the lessee for the execution of an oil and gas lease by the landowner. Bonus payments are also made to governments by oil and gas companies after concessions are awarded.
In a Bottom Hole Contribution the contributing party agrees to make a cash contribution to the drilling party in exchange for geological or drilling information, if a well is drilled to an agreed depth.
British Thermal Unit is traditionally defined as the amount of heat required to raise the temperature of 1 pound (lb) of water by 1 degree Fahrenheit. One Btu is more precisely defined as the amount of heat equivalent to 1,055.06 Joule.
BTX is the acronym used for the aromatics mixture of benzene, toluene, and xylene.
Btu is the acronym for British Thermal Units which is a measure of energy.
Bullet tanks are horizontal pressure tanks that are the shape of a very fat bullet. Bullet tanks are used to store normal butane, propane, and propylene.
Bunker fuel oil is a heavy, residual fuel oil used in ships' boilers and large electric power generating plants.
The Bureau of Land Management (BLM) owns the mineral rights of federal lands and administers leasing and drilling.
Butane (C4H10) is a chemical used as a fuel, petrochemical feedstock and for vapor pressure control in gasoline blending.
Butylene (C4H8) is a colorless, flammable and liquefied gas with detectable odor. Butylenes are formed during the cracking (breaking down of large molecules) of petroleum fractions. It is used for the production of high-octane gasoline, secondary and tertiary butyl alcohols, and synthetic rubber.
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Caprock is a hard impervious formation that forms a cap over permeable layers of sedimentary rock. This prevents the further upward migration of oil and gas and traps the hydrocarbon.
Carbon black is also known as Channel black, Lamp black, Furnace black, Thermal black or Acetylene black. It is an odorless solid; mainly used in automobile tire manufacture and road construction.
Carbonate rocks are "Chemical or Biochemical" in origin; they form within the basin of deposition, and are called Intrabasinal Rocks; composes of calcite and argonite; has high porosity and permeability and where scientist usually find oil and gas.
Carried Interest is interest created from an oil and gas lease that is free of some or all of the costs.
Casing is installed during the drilling process to: protect potable water zones near the surface from contamination, provide a smooth conduit for moving tools into and out of the hole, isolate down hole zones so they can be produced separately and protect the hole from the drilling fluids.
Chemical formula Gives the number and type of atoms making up a a chemical compound. It indicates the number of atoms of each element that are part of the compound.
Circulation process is the round trip made by the drilling mud; down through the drillpipe and back up the annulus between the pipe and the wall of the borehole. If circulation is lost, the flow out f the well is less than the flow into the well; the mud may be escaping into some porous formation or a cavity downhole.
The circulating system pumps drilling fluids down the hole, out of the nozzles in the drilling bit, and returns them to the surface where the debris is separated from the fluid.
Compressed natural gas (CNG) is natural gas that is under pressure. The pressure reduces the volume occupied for the gas so it can be contained in a smaller vessel.
Conveyance is a transfer of ownership of a property from one party to another.
Crude oil is the petroleum liquids as they come from the ground; formed from animal and vegetable material which collected at the bottom of ancient seas.
Cryogenic recovery processes are done at temperatures lower than -150 °F. The low temperatures allow the plant to recover over 90% of the ethane in the natural gas. Most new gas processing plants use cryogenic recovery technology.
Custody relates to when the ownership of oil changes. A run ticket is prepared for the receiver and the shipper to record the transaction.
Cuttings are chips and small fragments of rocks as the result of drilling that are brought to the surface by the flow of drilling mud as it is circulated. Cuttings are important to geologist, who examines them for information concerning the type of rock being drilled.
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Darcy is a unit of permeability of rock. A rock of one Darcy permeability is one in which fluid centipoise viscosity will flow at a velocity of one centimeter. Since a Darcy is too large a unit for most oil producing rocks, permeabilities used in the oil industry are expressed in units one thousands as large i.e. millidarcies (0.001 Darcy). Commercial oil and gas exhibit permeabilities ranging from a few millidarcies to several thousand.
Deadweight is the weight in tons that a an oil tanker can carry.
Depleted fields are the used up oil reservoirs that are used most often to store natural gas and comprise the majority of storage.
A derrick is a wooden or steel structure built over a well site to provide support for the drilling equipment and a tall mast for raising and lowering drillpipe and casing. A derrick is also referred to as a drilling rig.
A derrickhand is a member of the crew who works upon in the derrick on the tubing board racking tubing or the drillpipe as it is pulled from the well and unscrewed by the other crew members on the derrick floor.
Desiccant Drying The use of drying agent to remove moisture from a stream of oil or gas. In certain product pipelines great effort is made to remove all the water vapor before putting the line into service. To accomplish this, desiccant-dried air or an inert gas is pumped through is pumped through the line to absorb the moisture that may be present even in the ambient air in the line.
Development Well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
A diamond drill bit is made by setting man-made diamonds in the tip or the cutting surface of the bit. Diamonds are many times harder than the harder than the hardest steel, so diamond bit makes it possible longer bits run before a round trip is necessary to change the bits.
Diesel fuel is a middle distillate fuel similar to home heating oil that is used for fuel in trucks, trains, and ship engines.
Distillation is a process that uses the difference in boiling points of molecules and petroleum fractions to separate the compounds and streams.
A division order is a statement executed by all parties who claim an interest stipulating how proceeds of production are to be distributed.
Drawworks is the name for the hoisting drum, cable, shaft, clutches, power take off, brakes, and other machinery used on the drilling rig. Drawworks are located on one side of the derrick floor and serve as a power control center for the hoisting gear and the rotary elements of the drill column.
Drill bit is the mechanism that cuts into the ground layers to reach the gas deposit or to cut a core sample. Bits rotate 50-300 revolutions per minute depending upon the hardness of the strata through which it is boring. The diameter of a hole may be up to 24 inches but it is usually five to eight and one-half inches.
The drill collar is a heavy, tubular connector between drillpipe and a bit. Originally, the drill collar was a means of attaching the drill bit to the drillpipe and to strengthen the lower end of the drill column, which is subject to extreme compression, torsion, and bending stresses. Now the drill collar is used to concentrate a heavy mass near the lower end of the drill column. Drill collars were once a few feet long and weighed 400 or 500 pounds. Today because of the increased bit pressure and rapid rotation, collars are made up in 1000-foot lengths and weigh 50 to 100 tons.
The lease drilling-delay rental clause ensures that the lessee has no obligation to drill during the primary term. The drilling-delay clause includes "Unless" or "Or" clauses. The "Unless" clause says that the lease terminates unless a well is begun or delay rentals are paid prior to a specified date. The "Or" clause states that a lessee must either commence drilling or pay rentals or surrender the lease prior to the due date.
Drill pipe is heavy, thick-walled steel pipe used in rotary drilling to turn the drill bit and to provide a conduit for the drilling mud. Joints of drill pipe are about 30 feet long.
Drill string As the hole gets deeper, pipe is added to the drill bit to allow it to dig further. These lengths of drill pipe form the drill string.
Driller is the member of the drilling crew who operates a drilling rig; the person in charge of drilling operations and who supervises the drilling crew.
Drilling contractor/Service company is a person or a company whose business is drilling wells. Wells are drilled on a per foot basis, others are contracted for a day rate.
The drilling crew is composed of a toolpusher, a driller, a derrickhand, and several roughnecks.
Drilling fluid/mud is a special mixture of clay, water, and chemical additives pumped down-hole through the drillpipe and the drill bit. The mud cools the rapidly rotating bit; lubricates the drill pipe as it turns in the wellbore; carries rock cuttings to the surface; and serves as a plaster to prevent the wall of the borehole from crumbling or collapsing. It also provides the weight or hydrostatic head to prevent extraneous fluids from entering the wellbore and to control downhole pressures that may be encountered.
Drilling line are pipes that are made in even sizes from 2 inches to 48 inches. There are larger sizes in use however; some large gravity loading lines for crude oil tankers are 56 inches. Most line pipe either is lap welded or butt welded. Seamless pipe is usually only for drilling wells. Line pipes especially the large sizes, has beveled weld ends so the joints can be welded together. Largediameter screw pipe (12 inches) went out of style in the late 1920’s, along with the 200-man pipe handling and pipelaying crews. Gas welding and then electric welding put them out of business.
Dry-bed adsorption is used to remove water and some of the natural gas liquids from the natural gas. The liquids are adsorbed on the surface of the desiccant such as silica gel.
A dry hole is an unsuccessful well. The well does not contain enough hydrocarbons to warrant completion.
A Dry Hole Agreement is where contributing party agrees to make a cash contribution if the drilling party drills a dry-hole. The drilling party generally agrees to provide geological and drilling information whether or not the well is a dry hole.
Dry Natural Gas is natural gas that has been conditioned, treated and natural gas liquids (ethane and heavier molecules) removed.
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Electric Logs record weak electrical currents that flow in the rock next to the wellbore and shows the thickness and boundaries of the rock layers. These logs help determine the amount of salt water present and the permeability.
Ethane (C2H6), The saturated hydrocarbon which is primarily extracted from natural gas, but also from recovered refinery gases. The United States and Canada have long been the dominant producers and consumers of ethane. The largest end use for ethane is as a feedstock for ethylene production.
Ethanol (C2H3OH) is a colorless liquid that burns to produce water and carbon dioxide. The vapors form an explosive mixture with air and may be used as a fuel in the internal combustion engine. It is most easily produced by the fermentation of carbohydrates. Ethanol has replaced MBTE as the source of oxygenates in the gasoline pool.
Ethylene (C2H4) is a colorless, flammable gas, with a faint odor. It is an unsaturated chemical formed by cracking of ethane and other feedstocks in an ethylene plant. It is an important raw material in manufacture of numerous petrochemicals.
Ethylene glycol (C2H6O2) is a colorless, sweet-tasting liquid completely miscible with water and many organic liquids. Ethylene glycol markedly reduces the freezing point of water. It is used primarily as an anti-freeze and in the manufacture of polyester fiber and film, as heat-transfer fluid, dehydrating agent for natural gas.
Ethylene oxide ([CH2] 2O) is a colorless, flammable and liquefied gas with a sweet odor. It is primarily used as a chemical intermediate for ethylene glycol and other chemicals such as nonionic surfactants, glycol ethers, ethanolamines, triethylene glycol, and diethylene glycol. It is used as a sterilant and fumigant in the health product and medical fields.
Exploratory well is a well that is not a development well, a service well, or a stratigraphic test well. Wells drilled to find the limits of an oil-bearing formation, often referred to as a pool, only partly developed.
Ex-ship refers to the delivery basis for most traditional long-term LNG contracts. Agreed price includes cost of freight and insurance for transporting the LNG by tanker to buyers' facilities. Usually contrasted with Free On Board (FOB).
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A Farmout Agreement is an agreement to assign an interest in acreage in return for drilling or testing operation on that acreage.
A fault is a fracture in the earth's crust accompanied by a shifting of one side of the fracture with respect to the other side; the point at which a geological strata "breaks off" or is sheared off by dropping of a section of the strata by settling.
A fault trap is formed by rock movement along a fault line.
The Federal Energy Regulatory Commission (FERC) is the federal agency that regulates interstate gas pipelines and interstate gas sales under the Natural Gas Act. The FERC is considered an independent regulatory agency responsible primarily to Congress, but it is housed in the Department of Energy.
The landowner is the fee simple owner of a tract of land holds the right to use, occupy and enjoy the surface of the land, and the air space above it (surface rights), plus all rights to minerals beneath it (mineral rights).
Field gathering systems consist of pipelines that move oil from the wellhead to storage tanks and treatment facilities where the oil is measured and tested.
Fixed roof tanks are the refinery tanks used to store diesel, kerosene, catalytic cracker feedstock, and residual fuel oil.
Floating roof tanks are tanks with a flat roof that floats on the surface of the oil thus reducing evaporation to the minimum. The roof rests on a series of pontoons whose buoyancy supports the roof proper; a floater. These are used for storage of high volatile components such as gasoline, naphtha and benzene.
Fossil fuel is an energy source formed in the earth's crust from decayed organic material. The common fossil fuels are petroleum, coal, and natural gas.
FPSO stands for Floating Production, Storage and Offloading. This operation, based on a tanker, is used as a semi-permanent storage and loading facility for crude oil production in offshore fields.
A floating roof tank is a storage tank with a flat roof that floats on the surface of the oil thus reducing evaporation to the minimum. The roof rests on a series of pontoons whose buoyancy supports the roof proper; a floater. These are used for storage of high volatile components such as gasoline, naphtha and benzene.
Free On Board (FOB) refers to the costs associated with delivery, inspection and loading involved in putting crude oil, refined products or LNG on a tanker at sellers' facilities are included in agreed price. The buyer pays all additional costs to transport and unload the cargo.
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Gasoline is a light hydrocarbon mixture having C4 - C9 carbon atom hydrocarbons, which are used as, fuel for internal combustion engines.
Gathering stations receive oil through a gathering system from the producer's tanks.
Geologists are scientists who study the origin, history, composition, and structure of the earth and its life as recorded in rocks and other solid matter.
Geology is the science that involves the study of the earth and the earth's origin, composition, structure and history. Geology is the key to finding new sources of useful earth materials and to understanding earth processes that affect our lives.
Geophones are sensitive sound-detecting instruments used in conducting seismic surveys. A series of geophones is placed on the ground at intervals to detect and transmit to the amplifier-recording system the reflected sound waves created by explosions set off in the course of seismic exploration work.
The Granting Clause defines the rights that are “granted” by the mineral interest owner to the lessee.
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The Habendum Clause defines the period of time for which the rights given in the granting clause will extend. The habendum clause provides for a primary term which is a fixed term of years
during which the lessee has the right, without any obligation, to operate on the premises. It also describes a secondary term is the extended period of time for which rights are granted to the lessee once production is obtained.
Heating Value is the amount of energy or heat that is generated when a hydrocarbon is burned (chemically combined with oxygen). It is usually expressed in terms of Btus per unit of measurement.
The hoisting system is used to raise and lower pipe in and out of the hole and to support the drill string to control the weight on the drill bit during drilling.
Home heating oil is prepared from the middle distillate fractions of crude oil and is used to heat homes and businesses.
Hydrocarbons are molecules composed of hydrogen and carbon atoms… hence the name “hydrocarbons.”
Hydrophones are sound detecting instruments used in underwater seismic exploration activities. Hydrophones are attached to cable towed by seismic vessel. Sound waves generated by the blasts from air gun reflect from the formations below the sea floor and are picked up by the hydrophones and transmitted the mother ship.
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Inorganic theory says that oil and gas were produced during the formation of the solar system and the earth. The inorganic theory is often used to explain why oil and gas are found in unexpected places and differences in chemical composition.
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Jet fuel is a kerosene-based fuel that is used as a fuel for turbine engines in airplanes.
Joint Operating Agreement is a contract between co-tenants or separate owners of oil and gas properties being jointly operated. It defines the agreement with respect to initial drilling, further development, operations and accounting.
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The kelly is the first and the sturdiest joint of the drill column. It is a thick wall, hollow steel forging with two flat sides and two rounded sides that fits into the square hole in the rotary table that rotates the kelly joint and the drill column.
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A landman is a position in the oil and gas industry the responsibilities of which include acquiring oil and gas leases, negotiating arrangements for development of leases, and general management of leased property.
Landowner’s Royalty is an interest in production free of production costs retained by the lessor.
Large Range (LR) and Very Large Crude Carriers (VLCC) are employed in international crude oil trade. The size of tanker that can be used in any trade (commercial voyage between a port of origin and destination) is dependent on the tanker's length and loaded depth and the size of the loading and unloading ports. The larger ships are used because they reduce the cost to transport a barrel of crude oil.
Lease Automatic Custody Transfer (LACT) is a system of monitoring and transferring oil production for receiving into tankage, measuring, testing and turning into the pipeline the crude produced on a lease.
Leasehold interest is the right to the mineral interest granted by an oil and gas lease and is also called a working or operating interest.
The Lessee is an organization or individual who obtains a lease from a fee simple owner. In oil and gas, an organization or individual who obtains the mineral rights (the opportunity to look for oil and gas and produce the oil and gas found).
The Lessor is the fee simple owner or mineral rights owner who allows an individual or organization to explore for and produce oil and gas on mineral rights that he owns.
Liquefaction is the process by which gaseous natural gas is converted into liquid natural gas.
Liquefied Natural Gas (LNG) is natural gas that has been cooled to -260 F. and converted into a liquid so that it's volume will be reduced for transportation.
Liquefied Petroleum Gas (LPG) is a mixture of propane, propylene, butane and butylenes. When compressed moderately at normal temperature it becomes a liquid. It is obtain as light ends from fractionation of crude oil. It has a good caloric value; used as cooking fuel; because LPG has no natural odor, a distinctive odorant is added so that it will be noticeable should a leak occur.
LNG Tankers are double-hulled ships specifically designed to handle the low temperature of LNG, insulated to limit the amount of LNG that boils off. LNG carriers are up to 1,000 feet long, and require a minimum water depth of 40 feet when fully loaded.
Local distribution companies (LDCs) take possession of natural gas at the city gate distribute it to residential, commercial, industrial, and utility power users.
Lubricants (lubes) are specially formulated oils that reduce friction between moving parts and help maintain the mechanical parts. Lubricating oils are used in gasoline and other engines.
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Market aggregators are the marketers who collect customers and find suppliers to meet their demand. They work either on margin basis or on commission.
Methane is the primary ingredient of natural gas. The chemical formula is CH4.
The Minerals Management Service (MMS) of the Department of the Interior (DOI) is responsible for OCS leasing and production programs and royalty management.
The Mother Hubbard Clause “covers and includes any and all lands owned or claimed by the lessor adjacent or contiguous to the land.” It typically allows for additional 10% coverage of lands not included in the lease description.
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Natural gas is an odorless, colorless, tasteless, nontoxic clean-burning fossil fuel. Natural gas is largely methane (CH4) a naturally occurring gas that can also be produced by coal gasification. At times it contains ethane, propane, butane, pentane, helium and hexane.
Natural gas conditioning and treating removes solids (sand, pipe scale, dirt), water (dehydration), acid gases (hydrogen sulfide), and carbon dioxide and nitrogen.
Natural gas liquids (NGLs) are the heavier hydrocarbons or ethane (C2H6), propane (C3H8), butane (C4H10), and natural gasoline which are need to separated before transportation of natural gas in pipelines.
Non-Participating Royalty is a royalty “carved out” of the mineral interest that is often used by mineral interest owners who sell their rights.
Nuclear logs record natural and induced radioactivity and measures the amount of oil, gas and water; the type of rock and porosity; and the salt content.
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Organic theory says that oil and gas were formed from the remains of plants and animals. Scientists, who support this theory, think that oil and gas were formed from the remains of small or microscopic plants and animals that lived in prehistoric rivers and seas. When these plants and animals died they combined with mud, silt, and sand to form layers of the mixture called sediments. After thousands of years, a thick layer of sediment formed on the bottom of the sea. As more layers were added the weight of the new layers applied pressure to the lower layers and turned them into sedimentary rock. Scientists believe that high heat and pressure, bacteria, chemical reactions, and other forces transformed these sediments into oil and gas.
Original Oil/Gas in Place (OOIP or OGIP ) is an estimate of the amount of oil or gas contained in the reservoir based on physical features of the reservoir. Not all of these hydrocarbons can be recovered.
The Federal Government controls the area from the states’ inland waters out to 200 miles or 8,200 ft. of water depth. This region is known as the Outer Continental Shelf or OCS.
Overriding Royalty is an interest “carved out” of the lessee’s leasehold interest and is often used to compensate people who structured the drilling venture
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Petrochemicals are a class of chemicals that are derived from crude oil and natural gas. The primary petrochemical "building blocks" are benzene, toluene, and xylene (BTX) and ethylene. Over 3,000 chemical products are synthesized from these chemicals.
Permeability is a measure of the resistance offered by the rock to the movement of fluids through it. Permeability is one of the important properties of sedimentary rock containing petroleum deposits. The oil contained in the pores cannot flow into the wellbore if the rock in the formation lacks sufficient permeability. Such a formation is referred to as "tight."
A permeability trap occurs when a change of permeability within a trap seals off hydrocarbons in a portion of the rock layer. The changes may be caused by the uneven distribution of sand and clay as the sediment was deposited. This type of strategraphic trap is also called a lenticular trap.
Petroleum coke is a solid carbon substance that is deposited on the catalyst in fluid catalytic cracking and is isolated in the thermal coking process.
Petroleum geologists study the earth and as such they are important in the search for mineral resources and petroleum. Petroleum geologists are employed by oil companies to determine whether a region may produce oil or gas.
A pinchout trap is an unconformity where the older, eroded layer of rock is igneous and the newer layer is sedimentary. An unconformity trap can form if part of a porous layer of rock is eroded and then covered with an impermeable caprock. A good example of this structural trap is the East Texas field.
Pipelines are tubular arrangement for the transmission of crude oil, refined products, and natural gas from the wellhead, refinery, and storage facility to the customer. Pipeline measures 14 to 42 inches in diameter, but is usually 20 to 36 inches. It is often composed of 40-foot lengths but lengths may be as long as 60 or 80 feet. The pipe is wrapped and coated for protection against corrosion, especially since it runs underground. About half of all gas and oil is moved by pipeline.
To plug a well is to fill a well’s borehole with cement or other impervious material to prevent the flow of water, gas or oil from one strata to another when a well is abandoned; to screw a metal plug into a pipeline to shut off drainage or to divert the stream of oil to a connecting line; to stop the flow of oil or gas.
Polyethylene (-C2H2 -C2H2-)n is a petroleum derived plastic material used for packaging, plastic household-wares, and toys. The main ingredient of polyethylene is the petrochemical gas ethylene.
Polystyrene (C8H8)n is a white colored polymer made from polymerization of a styrene monomer.
Polyvinyl chloride (PVC) (CH2=CHCl) n is a hard, amber-colored material; precise properties depend on formulation. It is made from polymerization of vinyl chloride. Heat and light degrade all PVC polymers.
Pores are the minute or microscopic voids in porous rock. Rocks containing pores are able to hold oil, gas and water. If the pores are interconnected, the rock is permeable and a good reservoir rock.
Porosity is a measure of the volume contained in a rock. The volume of the pore space expressed as a percent of the total volume of the rock mass and is an important property of hydrocarbonbearing formations. Good porosity indicates an ability to hold large amounts of oil and gas in the rock.
Pounds per Square Inch (psi) is pressure measured with respect atmosphere pressure. This is a pressure gauge reading in which the gauge is adjusted to read zero at the surrounding atmospheric pressure.
A drilling rig receives its power from a system comprised of the diesel engine-DC generator-DC motor. A typical engine generator-motor include four such sets: two for the mud pumps, one for the drawworks and the rotary table, and one somewhat smaller size for the lighting and auxiliary loads. Another type of electric rig uses the same power-flow system but the generators are AC, whose current is converted to DC current to drive the DC motors for the variable speed drilling operations.
Pressure, Absolute (PSIA) is the gauge pressure plus barometric or atmospheric pressure. Absolute pressure can be zero only in a perfect vacuum. The pressure due to the weight of the atmosphere (air and water vapor) on the earth's surface. The average atmospheric pressure at sea level has been defined as 14.696 pounds per square inch absolute.
Propane (C3H8) is a hydrocarbon that is gaseous at ordinary atmospheric conditions but readily converted to a liquid. When in liquid state propane must be stored in a high-pressure metal container. Propane is odorless, colorless, and highly volatile. It is used as a household fuel beyond the gas mains.
Propylene (C3H6), can be obtained from petroleum oils during the refining of gasoline or by catalytic or thermal cracking of naphtha or natural gas liquids, or by catalytic dehydrogenation of propane; used in the manufacture of plastics; food storage containers, diapers and children's toys.
Propylene oxide (C3H6O) is a is a colorless liquid with an ether-like odor that is used mainly as a chemical intermediate in the production of polyurethane polyols, which are used to make polyurethane foams, coatings, and adhesives.
Propylene glycol (C3H8O2) is a clear colorless viscous liquid produced commercially from propylene oxide; has been widely used in pharmaceutical manufacturing as a solvent and vehicle especially for drugs unstable or insoluble in water industrial antifreeze.
Proved reserves are oil and gas that have been discovered and determined to be recoverable under prevailing economic and technical conditions.
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Quad is shorthand for quadrillion (1015) and is usually used in association with measuring energy consumption and supply in Btus.
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A refinery is a large plant composed of many different processing units that are used to convert crude oil into finished or refined products. These processes include heating, fractionating, reforming, cracking, and hydrotreating.
Refined products are the various hydrocarbons obtained as a result of refining process separation from crude oil. Typical refined products are LPG, naphtha, gasoline, kerosene, jet fuel, home heating oil, diesel fuel, residual fuel oil, lubricants and petroleum coke.
Refrigeration is the process used to remove the natural gas liquids by cooling or refrigerating the natural gas until the liquids are condensed out. The plants use Freon or propane to cool the gas.
A Regasification terminal is a facility for receiving, unloading, storing and re-gasifying LNG, usually including breakwaters, tanker berthing and other marine facilities.
Reserves are the supply of an oil or gas resource. Reserves are qualified to show degree of certainty such as proven reserves to possible and speculative reserves.
Reserve lifetime or R/P ratio is the ratio of the reserves of crude oil or natural gas in units of barrels or cubic feet to the annual production in barrels per year or cubic feet per year. The units of this ratio are years and is equivalent to the number of years of production left in the reserve at the current production rate.
Reserve Replacement is the ratio of additions to reserves divided by production. It is a measure of the extent to which production is being replaced.
Reserves are the amount of an oil or gas resource. Reserves are qualified to show degree of certainty such as proven reserves to possible and speculative reserves.
Reservoir rock is a layer of rock with interconnected holes and voids, into, and out of which, petroleum can flow.
Reservoirs are discrete sections of porous rock containing an accumulation of oil/gas, either separately or as a mixture.
Residual fuel oil is a low grade of fuel oil; used in the industry as boiler fuel; also known as bunker fuel in large ocean-going tankers.
A rig barge is a drilling rig mounted on a barge-like vessel for drilling in shallow water or swampy locations. Barge rigs are not self propelled and must be towed or pushed by a towboat. In addition to all necessary drilling equipment, barges also have quarters for the drilling crew.
A roller drill bit is a rock cutting tool on the bottom of the drillstring made with three or four shanks welded together to form a tapered body. Each shank supports a cone-like wheel with casehardened teeth that rotate on steel bearings.
The rotary table is a heavy, circular structure mounted on a steel platform just above the derrick floor with an opening in the center through which the drillpipe and casing must pass. The table is rotated by power transmitted from the drawworks and the drilling engines. In drilling, the kelly joint fits into the square opening of the table. As the table rotates, the kelly is turned, rotating the drill column and the drill bit.
Roughnecks are members of the drilling crew who work on the derrick floor and up in the derrick racking pipe. They operate and maintain the drilling engines and the mud pumps. They operate the pipe tongs to break out or unscrew the stands of the drill pipe during "trips."
Royalty Interest is a share of production free from the costs of production, when and if there is oil and gas production on the property.
A run ticket is used in buying and selling crude oil. When the ownership or custody of oil changes, a run ticket is prepared for the receiver and the shipper to record the transaction. The ticket is made in triplicate by the gauger and is witnessed by the lease owner’s representative, usually the pumper. The run ticket, an invoice for oil delivered shows opening and closing gauge, API gravity and temperature, tank temperature and BS&W. The original of the ticket goes to the purchaser; copies go to the pumper and one for the gauger.
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Salt caverns are solution mined in sufficiently thick salt formations - bedded salt or salt domes penetrated by boreholes down to depths of 2000 meters. The dimensions of the caverns normally extend to 300 meters in height and 60 meters in diameter, with volumes which generally range from 100, 000 - 800,000 cubic meters.
A salt dome is a subsurface mound or dome of salt. Two types of salt domes are recognized: the piercement and non-piercement. Piercement domes thrust upwards into the formations above them, causing faulting; non-piercement domes are produce by local thickening of the salt beds and merely lift the overlying formations to form an anticline.
Sandstones are generally considered the most porous and permeable rocks and are therefore where scientists usually find oil and gas.
Seal rock is a layer of rock through which oil and gas cannot flow.
When the demand for a product changes during different periods of the year, the product is said to be seasonal. The consumption of natural gas is seasonal. We use more gas in the winter to heat our homes than we do in the summer.
Sedimentary rocks are formed in horizontal layers when sediments from rivers are washed into lakes or oceans. The weight of the additional sediments compresses the earlier deposits and minerals cement them together into sedimentary rocks such as sandstone, limestone (carbonate) and shale.
Seeps provide evidence of hydrocarbons. Seeps occur along fractures in reservoirs or at places where the earth's surface cuts the formation.
2D seismic is a two-dimensional picture of the subsurface. It generates a seismic section, which is a two-dimensional slice from the surface of the earth downward. This section is known as 2D seismic because it shows the width and depth.
3D seismic is a new technique that scientists are now applying seismic technology to produce three-dimensional images of the earth's subsurface. Three-dimensional seismic or 3D seismic creates an image that includes length, width, and depth. Seismic crews obtain data on a 2 or 3 mile square of the earth's surface. Large, high-speed computers analyze the data and create a picture of the surface. Scientists can then take slices of this in a variety of directions to examine the formation.
4D seismic is a technique that is used at different time periods to study the movements of hydrocarbons. This produces a 4D seismic history of the formation with time as the fourth dimension.
Seismic surveys are geophysical information on subsurface rock formations gathered by means of a seismograph; the investigation of underground strata by recording and analyzing shock waves artificially produced and reflected from the subsurface bodies of the rock.
A seismograph amplifies and records the electrical signal and produces a picture or seismogram.
The seismograph is a device that records vibrations from the earth. In the exploration for oil and gas, a seismograph records shock waves set off by explorations detonated in the shot holes and picked up by geophones. This allows geoscientists to develop a map of the rock formations below the earth's surface.
Seismology is the science of study of the rocks below the surface of the earth.
Shale shaker is a vibrating screen for sifting out rock cuttings from the drilling mud. Drilling mud returning from downhole carrying rock chips in suspension flows over and through the mesh of the shale shaker, leaving small fragments of rocks and are collected and examined by the geologist for information on the formation being drilled.
Sour crude oil containing a degree of sulfur as hydrogen sulfide and other sulfur compounds. Has a pungent smell and sulfur content is controlled before fractionation of crude oil.
Source rock is a layer of rock containing organic material that naturally transforms into petroleum.
Spherical tanks can withstand higher pressures per square inch; they are used for storage of isobutane and normal butane.
Stratigraphic trap is a type of reservoir capable of holding oil and gas, formed by a change in characteristics of the formation – loss of porosity and permeability, or a break in its continuitywhich forms the trap or reservoir.
Sulfur is a yellowish white solid. Sulfur appears in oil and gas in the form of hydrogen sulfide or in combination with a hydrocarbon to form a mercaptan. Sulfur is an undesirable component because when the product is burned it forms sulfur oxides, which contribute to air pollution.
Supply aggregators is a description applied to natural gas marketers who collect natural gas production from producers and find markets for the gas.
Surface geology uses physical features on the earth's surface to give an indication of the presence of structural traps such as anticlines.
Surfactants or surface-active agents are substances with special properties that are used in detergents, cosmetics, dyes, and dispersants.
Sweet crude gets its name because it has a "sweet" or pleasant smell. Sweet crude has a sulfur content less than 1%. It is more valuable than sour crude because it costs less to process the crude into finished products.
The swivel is part of the well-drilling system. It is a heavy, steel casting equipment with a bail-held by the hook of the traveling block-containing the wash pipe, gooseneck, and bearings on which the kelly joint hangs and rotates. It is the heavy link between the hook and the drill string onto which the mud house is attached.
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Tankers are used to transport crude oil and refined products in waterborne trade. The tankers can be used in either "clean" (light refined products such as gasoline and diesel fuel) or "dirty" (residual fuel and crude oil) trade. The tankers range in size from the small vessels used to transport refined products to huge crude carriers. Tanker sizes are expressed in terms of deadweight tons (dwt). The smallest tankers are General Purpose which range from 10 to 25,000 tons and the largest are . These tankers are used to transport refined products. Tankers are unloaded/loaded at the jetties or the specially build piers.
Terminals are strategic locations owned by the refineries for storage and distribution of their refined products. The products are taken to pumps via tankers from the terminals. They keep record of the inventory coming in and out.
Toluene An aromatic hydrocarbon resembling benzene but less volatile and flammable. It is used as a solvent and as an antiknock agent in gasoline.
A toolpusher is the supervisor of drilling operation in the field. A toolpusher may have one drilling well or several under his direct supervision. Drillers are directed in their work by the toolpusher.
An LNG train is a processing unit that converts natural gas into a liquid. An LNG plant comprises one or more LNG trains, each of which is an independent unit for gas liquefaction.
A trap prevents oil and gas from rising to the earth's surface. A trap consists of a layer of rock that oil and gas cannot penetrate (impermeable) above a porous, permeable layer that holds the oil and gas. These traps can take many forms but a common type would be in the shape of an inverted bowl formed from impermeable rock. Traps are formed by changes in the earth's crust such as folding or faulting.
Traveling and crown blocks are the large, heavy-duty block hanging in the derrick and to which the hook is attached. The travelling block supports the drill column and "travels" up and down as it hoists the pipe out of the hole and lowers it in. The traveling block may contain from three to six sheaves depending upon the loads to be handled and the mechanical advantage necessary. The wireline from the hoisting drum on the drawworks runs to the derrick’s crown block and down to the traveling block’s sheaves. The crown block is a stationary pulley located at the top of the derrick.
Trunkline stations receive oil from the gathering station and move the oil to the refineries and shipping terminals. Booster pumps are located along the line to maintain system pressure.
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Vacuum Distillation is a refinery process that separates atmospheric residua into a light and heavy fraction. It takes place under reduced pressure (less than atmospheric) which allows the distillation to take place at a lower temperature. The lower temperature prevents cracking and coke formation.
Vinyl acetate (C4H6O2) is a colorless, clear liquid with a sweet fruity; it does not occur naturally in the environment. Vinyl acetate readily evaporates into air and dissolves easily in water; it is flammable and may be ignited by heat, sparks, or flames. It is primarily used in the production of polyvinyl acetate and polyvinyl alcohol, which are widely used in adhesives for packaging and construction, and in water-based paints.
Vinyl chloride is a colorless, flammable gas (CH2=CHCl) with a faintly sweet odor. It liquefies in a freezing mixture, and polymerizes in light, air, or heat unless stabilized by inhibitors such as phenol. It is industrially important because of the inherent flame-retardant properties of its polymer. It is a monomer for polyvinyl chloride (PVC), a plastic resin used in innumerable consumer and industrial products.
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Wet natural gas is natural gas from the wellhead. The gas may have undergone some conditioning and treating to remove water, solids and carbon dioxide but it still contains heavier hydrocarbons (ethane and heavier).
Wireline logs use a wire and conductor line to lower a logging tool into the completed well.
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Xylene (C8H10) is a flammable, toxic aromatic hydrocarbon liquid. Xylene is related to benzene and can be distilled or synthesized.
Go to the Index Processing & Refining Crude Oil
Chevron's Pascagoula Refinery processes 330,000 barrels (13.9 million gallons) of crude oil a day an amount equivalent to the size of a football field covered to a depth of 40 feet. Operators control the refining processes using hi-tech computers located in control centers situated throughout the refinery. Hi-Tech Process Control
Using the latest electronic technology to monitor and control the plants, operators run the process units 24 hours a day, 7 days a week. From control rooms located in each Operations area,
operators use a computer-driven process control system with console screens that display color interactive graphics of the plants and real-time data on the status of the plants. The process control system allows operators to "fine-tune" the processes and respond immediately to process changes. With redundancy designed into the control system, safe operations are assured in the event of plant upset. Refining's Basic Steps
Most refineries, regardless of complexity, perform a few basic steps in the refining process: DISTILLATION, CRACKING, TREATING and REFORMING. These processes occur in our main operating areas – Crude/Aromatics, Cracking I, RDS/Coker, Cracking II, and at the Sulfur Recovery Unit. 1. Distillation
Modern distillation involves pumping oil through pipes in hot furnaces and separating light hydrocarbon molecules from heavy ones in downstream distillation towers – the tall, narrow columns that give refineries their distinctive skylines.
The Pascagoula Refinery's refining process begins when crude oil is distilled in two large Crude Units that have three distillation columns, one that operates at near atmospheric pressure, and two others that operate at less than atmospheric pressure, i.e., a vacuum.
Click on image for Distillation Column Diagram
During this process, the lightest materials, like propane and butane, vaporize and rise to the top of the first atmospheric column. Medium weight materials, including gasoline, jet and diesel fuels, condense in the middle. Heavy materials, called gas oils, condense in the lower portion of the atmospheric column. The heaviest tar-like material, called residuum, is referred to as the "bottom of the barrel" because it never really rises.
This distillation process is repeated in many other plants as the oil is further refined to make various products.
In some cases, distillation columns are operated at less than atmospheric pressure (vacuum) to lower the temperature at which a hydrocarbon mixture boils. This "vacuum distillation" (VDU) reduces the chance of thermal decomposition (cracking) due to over heating the mixture.
As part of the 2003 Clean Fuels Project, the Pascagoula Refinery added a new low-pressure vacuum column to the Crude I Unit and converted the RDS/Coker's VDU into a second vacuum column for the Crude II Unit. These and other distillation upgrades improved gas oil recovery and decreased residuum volume.
Using the most up-to-date computer control systems, refinery operators precisely control the temperatures in the distillation columns which are designed with pipes to withdraw the various types of products where they condense. Products from the top, middle and bottom of the column travel through these pipes to different plants for further refining. 2. Cracking
Since the marketplace establishes product value, our competitive edge depends on how efficiently we can convert middle distillate, gas oil and residuum into the highest value products.
At the Pascagoula Refinery, we convert middle distillate, gas oil and residuum into primarily gasoline, jet and diesel fuels by using a series of processing plants that literally "crack" large, heavy molecules into smaller, lighter ones.
Heat and catalysts are used to convert the heavier oils to lighter products using three "cracking" methods: fluid catalytic cracking (FCC), hydrocracking (Isomax), and coking (or thermal-cracking).
The Fluid Catalytic Cracker (FCC) uses high temperature and catalyst to crack 86,000 barrels (3.6 million gallons) each day of heavy gas oil mostly into gasoline. Hydrocracking uses catalysts to react gas oil and hydrogen under high pressure and high temperature to make both jet fuel and gasoline.
Also, about 58,000 barrels (2.4 million gallons) of lighter gas oil is converted daily in two Isomax Units, using this hydrocracking process.
We blend most of the products from the FCC and the Isomaxes directly into transportation fuels, i.e., gasoline, diesel and jet fuel. We burn the lightest molecules as fuel for the refinery's furnaces, thus conserving natural gas and minimizing waste.
In the Delayed Coking Unit (Coker), 98,000 barrels a day of low-value residuum is converted (using the coking, or thermal-cracking process) to high-value light products, producing petroleum coke as a by-product. The large residuum molecules are cracked into smaller molecules when the residuum is held in a coke drum at a high temperature for a period of time. Only solid coke remains and must be drilled from the coke drums.
Modifications to the refinery during its 2003 Clean Fuels Project increased residuum volume going to the Coker Unit. The project increased coke handling capacity and replaced the 150 metric-ton coke drums with new 300 metric-ton drums to handle the increased residuum volume.
The Coker typically produces more than 6,000 tons a day of petroleum coke, which is sold for use as fuel or in cement manufacturing. Combining
While the cracking processes break most of the gas oil into gasoline and jet fuel, they also break off some pieces that are lighter than gasoline. Since Pascagoula Refinery's primary focus is on making transportation fuels, we recombine 14,800 barrels (622,000 gallons) each day of lighter components in two Alkylation Units. This process takes the small molecules and recombines them in the presence of sulfuric acid catalyst to convert them into high octane gasoline.
3. Treating (Removing Impurities)
The products from the Crude Units and the feeds to other units contain some natural impurities, such as sulfur and nitrogen. Using a process called hydrotreating (a milder version of hydrocracking), these impurities are removed to reduce air pollution when our fuels are used.
Because about 80 percent of the crude oil processed by the Pascagoula Refinery is heavier oils that are high in sulfur and nitrogen, various treating units throughout the refinery work to remove these impurities.
In the RDS Unit's six 1,000-ton reactors, sulfur and nitrogen are removed from FCC feed stream. The sulfur is converted to hydrogen sulfide and sent to the Sulfur Unit where it is converted into elemental sulfur. Nitrogen is transformed into ammonia which is removed from the process by water-washing. Later, the water is treated to recover the ammonia as a pure product for use in the production of fertilizer.
The RDS's Unit main product, low sulfur vacuum gas oil, is fed to the FCC (fluid catalytic cracker) Unit which then cracks it into high value products such as gasoline and diesel. 4. Reforming
Octane rating is a key measurement of how well a gasoline performs in an automobile engine. Much of the gasoline that comes from the Crude Units or from the Cracking Units does not have enough octane to burn well in cars.
The gasoline process streams in the refinery that have a fairly low octane rating are sent to a Reforming Unit where their octane levels are boosted. These reforming units employ preciousmetal catalysts - platinum and rhenium – and thereby get the name "rheniformers." In the reforming process, hydrocarbon molecules are "reformed" into high octane gasoline components. For example, methyl cyclohexane is reformed into toluene.
The reforming process actually removes hydrogen from low-octane gasoline. The hydrogen is used throughout the refinery in various cracking (hydrocracking) and treating (hydrotreating) units.
Our refinery operates three catalytic reformers, where we rearrange and change 71,000 barrels (about 3 million gallons) of gasoline per day to give it the high octane cars need.
Product testing Blending
A final and critical step is the blending of our products. Gasoline, for example, is blended from treated components made in several processing units. Blending and Shipping Area operators precisely combine these to ensure that the blend has the right octane level, vapor pressure rating and other important specifications. All products are blended in a similar fashion. Quality Control
In the refinery’s modernly-equipped Laboratory, chemists and technicians conduct quality assurance tests on all finished products, including checking gasoline for proper octane rating. Techron® Chevron’s patented performance booster, is added to gasoline at the company’s marketing terminals, one of which is located at the Pascagoula Refinery.
STORAGE AND TRANSPORTATION OF CRUDE OIL, NATURAL GAS, LIQUID PETROLEUM PRODUCTS AND OTHER CHEMICALS
Richard S. Kraus
Pipelines, marine vessels, tank trucks, rail tank cars and so forth are used to transport crude oils, compressed and liquefied hydrocarbon gases, liquid petroleum products and other chemicals from their point of origin to pipeline terminals, refineries, distributors and consumers.
Crude oils and liquid petroleum products are transported, handled and stored in their natural liquid state. Hydrocarbon gases are transported, handled and stored in both the gaseous and liquid states and must be completely confined in pipelines, tanks, cylinders or other containers prior to use. The most important characteristic of liquefied hydrocarbon gases (LHGs) is that they are stored, handled and shipped as liquids, taking up a relatively small amount of space and then expanding into a gas when used. For example, liquefied natural gas (LNG) is stored at -162°C, and when it is released the difference in storage and atmospheric temperatures causes the liquid to expand and gasify. One gallon (3.8 l) of LNG converts to approximately 2.5 of natural gas at normal temperature and pressure. Because liquefied gas is much more “concentrated” than compressed gas, more useable gas can be transported and provided in the same size container.
Pipelines
It is generally the case that all crude oils, natural gas, liquefied natural gas, liquefied petroleum gas (LPG) and petroleum products flow through pipelines at some time in their migration from the well to a refinery or gas plant, then to a terminal and eventually to the consumer. Aboveground,
underwater and underground pipelines, varying in size from several centimetres to a metre or more in diameter, move vast amounts of crude oil, natural gas, LHGs and liquid petroleum products. Pipelines run throughout the world, from the frozen tundra of Alaska and Siberia to the hot deserts of the Middle East, across rivers, lakes, seas, swamps and forests, over and through mountains and under cities and towns. Although the initial construction of pipelines is difficult and expensive, once they are built, properly maintained and operated, they provide one of the safest and most economical means of transporting these products.
The first successful crude-oil pipeline, a 5-cm-diameter wrought iron pipe 9 km long with a capacity of about 800 barrels a day, was opened in Pennsylvania (US) in 1865. Today, crude oil, compressed natural gas and liquid petroleum products are moved long distances through pipelines at speeds from 5.5 to 9 km per hour by large pumps or compressors located along the route of the pipeline at intervals ranging from 90 km to over 270 km. The distance between pumping or compressor stations is determined by the pump capacity, viscosity of the product, size of the pipeline and the type of terrain crossed. Regardless of these factors, pipeline pumping pressures and flow rates are controlled throughout the system to maintain a constant movement of product within the pipeline.
Types of pipelines
The four basic types of pipelines in the oil and gas industry are flow lines, gathering lines, crude trunk pipelines and petroleum product trunk pipelines.
· Flow lines. Flow lines move crude oil or natural gas from producing wells to producing field storage tanks and reservoirs. Flow lines may vary in size from 5 cm in diameter in older, lowerpressure fields with only a few wells, to much larger lines in multi-well, high-pressure fields. Offshore platforms use flow lines to move crude and gas from wells to the platform storage and
loading facility. A lease line is a type of flow line which carries all of the oil produced on a single lease to a storage tank.
· Gathering and feeder lines. Gathering lines collect oil and gas from several locations for delivery to central accumulating points, such as from field crude oil tanks and gas plants to marine docks. Feeder lines collect oil and gas from several locations for delivery direct into trunk lines, such as moving crude oil from offshore platforms to onshore crude trunk pipelines. Gathering lines and feeder lines are typically larger in diameter than flow lines.
· Crude trunk pipelines. Natural gas and crude oil are moved long distances from producing areas or marine docks to refineries and from refineries to storage and distribution facilities by 1- to 3-mor larger-diameter trunk pipelines.
· Petroleum product trunk pipelines. These pipelines move liquid petroleum products such as gasoline and fuel oil from refineries to terminals, and from marine and pipeline terminals to distribution terminals. Product pipelines may also distribute products from terminals to bulk plants and consumer storage facilities, and occasionally from refineries direct to consumers. Product pipelines are used to move LPG from refineries to distributor storage facilities or large industrial users.
Regulations and standards
Pipelines are constructed and operated to meet safety and environmental standards established by regulatory agencies and industry associations. Within the United States, the Department of Transportation (DOT) regulates the operation of pipelines, the Environmental Protection Agency (EPA) regulates spills and releases, the Occupational Safety and Health Administration (OSHA) promulgates standards covering worker health and safety, and the Interstate Commerce Commission (ICC) regulates common carrier pipelines. A number of industry organizations, such as the American Petroleum Institute and the American Gas Association, also publish recommended practices covering pipeline operations.
Pipeline construction
Pipeline routes are planned using topographic maps developed from aerial photogrammetric surveys, followed by actual ground surveying. After planning the route, obtaining right-of-way and permission to proceed, base camps are established and a means of access for construction equipment is required. Pipelines can be constructed working from one end to another or simultaneously in sections which are then connected.
The first step in laying pipeline is to construct a 15- to 30-m-wide service road along the planned route to provide a stable base for the pipe-laying and pipe-joining equipment and for underground pipeline excavation and backfill equipment. The pipe sections are laid on the ground alongside the service road. The ends of the pipe are cleaned, the pipe is bent horizontally or vertically, as necessary, and the sections are held in position by chocks above the ground and joined by multipass electrical arc-welding. The welds are checked visually and then with gamma radiation to assure that no defects are present. Each connected section is then coated with liquid soap and airpressure tested to detect leaks.
The pipeline is cleaned, primed and coated with a hot, tar-like material to prevent corrosion and wrapped in an outer layer of heavy paper, mineral wool or plastic. If the pipe is to be buried, the bottom of the trench is prepared with a sand or gravel bed. The pipe may be weighed down by short, concrete sleeves to prevent its lifting out of the trench from groundwater pressure. After the underground pipeline is placed in the trench, the trench is backfilled and the surface of the ground returned to normal appearance. After coating and wrapping, aboveground piping is lifted up onto prepared stanchions or casements, which may have various design features such as antiearthquake shock absorption. Pipelines may be insulated or have heat trace capabilities to keep products at desired temperatures throughout transport. All pipeline sections are hydrostatically tested prior to entering gas or liquid hydrocarbon service.
Pipeline operations
Pipelines may be either privately owned and operated, carrying only the owner’s products, or they may be common carriers, required to carry any company’s products provided that the pipeline’s product requirements and tariffs are met. The three major pipeline operations are pipeline control, pumping or compressor stations and delivery terminals. Storage, cleaning, communication and shipment are also important functions.
· Pipeline control. Regardless of the product being transported, the size and length of the pipeline or the terrain, pipeline pumping stations, pressures and flow rates are completely controlled in order to ensure appropriate flow rates and continuous operations. Typically an operator and computer control the pumps, valves, regulators and compressors throughout the pipeline system from a central location.
· Oil pumping and gas compressor stations. Crude oil and petroleum products pumping stations and gas compressor stations are located at wellheads and along the pipeline route as needed to maintain pressure and volume. Pumps are driven by electric motors or diesel engines, and turbines may be powered by fuel oil, gas or steam. Many of these stations are automatically controlled and not staffed at most times. Pumps, with and without vapour return lines or pressure equalizing lines, are commonly used in smaller pipelines for transport of LNG, LPG and compressed natural gas (CNG). Pressure drop detectors are installed to signal any leaks in pipelines, and excess flow valves or other flow limiting devices are used to minimize the rate of flow in case of a pipeline leak. Storage vessels and reservoirs may be isolated from main pipelines by manually operated or remote control valves or fusible link valves.
· Pipeline product storage. Crude and petroleum product pipeline terminals have breakout storage tanks to which shipments may be diverted, where they are held until required by a refinery, terminal or user (see figure 102.14). Other tanks at pipeline pumping stations contain fuel for
operating diesel-driven pump motors or for running electrical generators. Because gas fields produce continuously and gas pipelines operate continuously, during times of reduced demand, such as summertime, liquefied natural and petroleum gases are stored underground in natural caverns or salt domes until needed.
· Pipeline cleaning. Pipelines are cleaned on a scheduled basis or as necessary in order to continue flow by reducing friction and maintaining as large a diameter interior as possible. A special cleaning device, called a pig or go-devil, is placed into the pipeline and pushed along by the flow of oil from one pumping station to the next. As the pig passes through the pipeline it scrapes off any dirt, wax or other deposits which have built up inside the pipeline walls. When it reaches a pumping station, the pig is removed, cleaned and reinserted into the pipeline to travel to the next station.
· Communications. It is important that there be communication and agreement concerning schedules, pumping rates and pressures and emergency procedures between pipeline stations and operators and those shipping and receiving crude oil, gas and petroleum products. Some pipeline companies have private telephone systems which transmit the signal along the pipeline, while others use radios or public telephones. Many pipelines use ultra-high-frequency microwave transmitter systems for computer communications between control centres and pumping stations.
· Petroleum product shipment. Petroleum products may be shipped a number of different ways on pipelines. A company operating a refinery may blend a specific grade of its own gasoline with appropriate additives (additize) and ship a batch through a pipeline directly to its own terminal for distribution to its customers. Another method is for a refinery to produce a batch of gasoline, called a frangible or specification product, which is blended to meet a common carrier pipeline company’s product specifications. The gasoline is placed into the pipeline for delivery to any company’s terminals which are connected to the pipeline system. In a third method, products are shipped by companies to each other’s terminals and exchanged in order to avoid extra transportation and handling. Frangible and exchange products are usually blended and additized at the terminal which receives the product from the pipeline, to meet the specific requirements of each company operating from the terminal. Finally, some products are delivered by pipeline from terminals and refineries direct to large commercial consumers-jet fuel to airports, gas to gas distribution companies and fuel oil to electric generating plants.
· Product receipt and delivery. Pipeline operators and terminal operators should jointly establish programmes to provide for the safe receipt and transfer of products and to coordinate actions in
case an emergency occurs on the pipeline or at the terminal during shipment which requires shutdown or diversion of product.
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Figure 102.14 A terminal operator transfers product the Pasagoula Refinery into holding tanks in the Deraville Terminal near Atlanta, Georgia, US
American Petroleum Institute
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Instructions for receiving pipeline deliveries should include verification of the availability of the storage tanks to hold the shipment, opening and aligning tank and terminal valves in anticipation of delivery, checking to assure that the proper tank is receiving product immediately after the start of delivery, conducting required sampling and testing of batches at the start of delivery, performing batch changes and tank switches as required, monitoring receipts to assure that overfills do not occur and maintaining communications between the pipeline and the terminal. The use of written communications between terminal workers, especially when shift changes occur during product transfer, should be considered.
Batch shipments and interface
Although pipelines originally were used to move only crude oil, they evolved into carrying all types and different grades of liquid petroleum products. Because petroleum products are transported in pipelines by batches, in succession, there is commingling or mixing of the products at the interfaces. The product intermix is controlled by one of three methods: downgrading (derating), using liquid and solid spacers for separation or reprocessing the intermix. Radioactive tracers, colour dyes and spacers may be placed into the pipeline to identify where the interfaces occur. Radioactive sensors, visual observation or gravity tests are conducted at the receiving facility to identify different pipeline batches.
Petroleum products are normally transported through pipelines in batch sequences with compatible crude oils or products adjoining one another. One method of maintaining product quality and integrity, downgrading or derating, is accomplished by lowering the interface between the two batches to the level of the least affected product. For example, a batch of high-octane premium gasoline is typically shipped immediately before or after a batch of lower-octane regular gasoline. The small quantity of the two products which has intermixed will be downgraded to the lower octane rating regular gasoline. When shipping gasoline before or after diesel fuel, a small amount of diesel interface is allowed to blend into the gasoline, rather than blending gasoline into the diesel fuel, which could lower its flashpoint. Batch interfaces are typically detected by visual observation, gravitometers or sampling.
Liquid and solid spacers or cleaning pigs may be used to physically separate and identify different batches of products. The solid spacers are detected by a radioactive signal and diverted from the pipeline into a special receiver at the terminal when the batch changes from one product to another. Liquid separators may be water or another product that does not commingle with either of the batches it is separating and is later removed and reprocessed. Kerosene, which is downgraded (derated) to another product in storage or is recycled, can also be used to separate batches.
A third method of controlling the interface, often used at the refinery ends of pipelines, is to return the interface to be reprocessed. Products and interfaces which have been contaminated with water may also be returned for reprocessing.
Environmental protection
Because of the large volumes of products which are transported by pipelines on a continuous basis, there is opportunity for environmental damage from releases. Depending on company and regulatory safety requirements and the pipeline’s construction, location, weather, accessibility and operation, a considerable amount of product may be released should a break in the line or leak occur. Pipeline operators should have emergency response and spill contingency plans prepared and have containment and clean-up materials, personnel and equipment available or on call. Simple field solutions such as building earth dykes and drainage ditches can be quickly implemented by trained operators to contain and divert spilled product.
Maintaining pipelines and worker health and safety
The first pipelines were made of cast iron. Modern trunk pipelines are constructed of welded, high-strength steel, which can withstand high pressures. Pipe walls are periodically tested for thickness to determine whether internal corrosion or deposits have occurred. Welds are checked visually and with gamma radiation to assure that no defects are present.
Plastic pipe may be used for low-pressure, small-diameter flow lines and gathering lines in gas and crude-oil-producing fields, since plastic is light in weight and easy to handle, assemble and move.
When a pipeline is separated by cutting, spreading flanges, removing a valve or opening the line, an electrostatic arc may be created by impressed cathodic protection voltage, corrosion, sacrificial anodes, nearby high-voltage power lines or stray ground currents. This should be minimized by grounding (earthing) the pipe, de-energizing the cathodic rectifiers closest to both sides of the separation and connecting a bonding cable to each side of the piping prior to starting work. As additional pipeline sections, valves and so on are added to an existing line, or during construction, they should first be bonded to the pipelines in place.
Work on pipelines should cease during electrical storms. Equipment used to lift and place pipe should not be operated within 3 m of high-voltage electric lines. Any vehicles or equipment working in the vicinity of high-voltage lines should have trailing grounding straps attached to the frames. Temporary metal buildings should also be grounded.
Pipelines are specially coated and wrapped to prevent corrosion. Cathodic electrical protection may also be required. After the pipeline sections are coated and insulated, they are joined by special clamps connected to metallic anodes. The pipeline is subjected to a grounded source of direct current of sufficient capacity so that the pipeline acts as a cathode and does not corrode.
All pipeline sections are hydrostatically tested prior to entering gas or liquid hydrocarbon service and, depending on regulatory and company requirements, at regular intervals during the life of the pipeline. Air must be eliminated from pipelines prior to hydrostatic testing, and hydrostatic pressure built up and reduced at safe rates. Pipelines are regularly patrolled, usually by aerial surveillance, to visually detect leaks, or monitored from the control centre to detect a drop in flow rate or pressure, which would signify that a break in the pipeline has occurred.
Pipeline systems are provided with warning and signalling systems to alert operators so they may take corrective action in an emergency. Pipelines may have automatic shutdown systems which activate emergency pressure valves upon sensing increased or reduced pipeline pressure. Manually or automatically operated isolation valves are typically located at strategic intervals along pipelines, such as at pumping stations and at both sides of river crossings.
An important consideration when operating pipelines is to provide a means of warning contractors and others who may be working or conducting excavations along the pipeline route, so that the pipeline is not inadvertently ruptured, breached or punctured, resulting in a vapour or gas explosion and fire. This is usually done by regulations which require construction permits or by pipeline companies and associations providing a central number which contractors can call prior to excavation.
Because crude oil and flammable petroleum products are transported in pipelines, the possibility exists for fire or explosion in case of a line break or release of vapour or liquid. Pressure should be reduced to a safe level before working on high-pressure pipelines. Combustible gas testing should be conducted and a permit issued prior to repair or maintenance involving hot work or hot tapping on pipelines. The pipeline should be cleared of flammable liquids and vapours or gas prior to starting work. If a pipeline cannot be cleared and an approved plug is used, safe work procedures should be established and followed by qualified workers. The line should be vented a safe distance from the hot work area to relieve any build-up of pressure behind the plug.
Proper safety procedures should be established and followed by qualified workers when hot tapping pipelines. If welding or hot tapping is conducted in an area where a spill or leak has occurred, the outside of the pipe should be cleaned of liquid, and contaminated soil should be removed or covered to prevent ignition.
It is very important to notify operators at the nearest pumping stations on each side of the operating pipeline where maintenance or repair is to be performed, in case shutdown is required. When crude oil or gas is being pumped into pipelines by producers, the pipeline operators must provide specific instructions to the producers as to actions to take during repair, maintenance or in an emergency. For example, prior to tie-in of production tanks and lines to pipelines, all gate valves and bleeders for the tanks and lines involved in the tie-in should be closed and locked or sealed until the operation is completed.
Normal safety precautions concerning pipe and materials handling, toxic and hazardous exposures, welding and excavation apply during pipeline construction. Workers clearing right-ofway should protect themselves from climatic conditions; poisonous plants, insects and snakes; falling trees and rocks; and so on. Excavations and trenches should be sloped or shored to prevent
collapse during underground pipeline construction or repair (see the article “Trenching” in the chapter Construction). Workers should follow safe work practices when opening and de-energizing electrical transformers and switches.
Pipeline operating and maintenance personnel often work alone and are responsible for long stretches of pipeline. Atmospheric testing and the use of personal and respiratory protective equipment is needed to determine oxygen and flammable vapour levels and protect against toxic exposures to hydrogen sulphide and benzene when gauging tanks, opening lines, cleaning spills, sampling and testing, shipping, receiving and performing other pipeline activities. Workers should wear dosimeters or film badges and avoid exposure when working with density gauges, source holders or other radioactive materials. The use of personal and respiratory protective equipment should be considered for exposure to burns from the hot protective tar used in pipe-coating operations and from toxic vapours which contain polynuclear aromatic hydrocarbons.
Marine Tankers and Barges
The majority of the world’s crude oil is transported by tankers from producing areas such as the Middle East and Africa to refineries in consumer areas such as Europe, Japan and the United States. Oil products were originally transported in large barrels on cargo ships. The first tanker ship, which was built in 1886, carried about 2,300 SDWT (2,240 pounds per ton) of oil. Today’s supertankers can be over 300 m long and carry almost 200 times as much oil (see figure 102.15). Gathering and feeder pipelines often end at marine terminals or offshore platform loading facilities, where the crude oil is loaded into tankers or barges for transport to crude trunk pipelines or refineries. Petroleum products also are transported from refineries to distribution terminals by tanker and barge. After delivering their cargoes, the vessels return in ballast to loading facilities to repeat the sequence.
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Figure 102.15
SS Paul L. Fahrney oil tanker
American Petroleum Institute
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Liquefied natural gas is shipped as a cryogenic gas in specialized marine vessels with heavily insulated compartments or reservoirs (see figure 102.16). At the delivery port, the LNG is offloaded to storage facilities or regasification plants. Liquefied petroleum gas may be shipped both as a liquid in uninsulated marine vessels and barges and as a cryogenic in insulated marine vessels. Additionally, LPG in containers (bottled gas) may be shipped as cargo on marine vessels and barges.
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Figure 102.16
LNG Leo tanker loading at Arun, Sumatra, Indonesia
American Petroleum Institute
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LPG and LNG marine vessels
The three types of marine vessels used for transport of LPG and LNG are:
· vessels with reservoirs pressurized up to 2 mPa (LPG only)
· vessels with heat-insulated reservoirs and a reduced pressure of 0.3 to 0.6 mPa (LPG only)
· cryogenic vessels with heat-insulated reservoirs pressurized close to atmospheric pressure (LPG and LNG).
Shipment of LHGs on marine vessels requires constant safety awareness. Transfer hoses must be suitable for the correct temperatures and pressures of the LHGs being handled. To prevent a flammable mixture of gas vapour and air, inert gas (nitrogen) blanketing is provided around reservoirs, and the area is continually monitored to detect leaks. Before loading, storage reservoirs should be inspected to ensure that they are free of contaminants. If reservoirs contain inert gas or air, they should be purged with LHG vapour prior to loading the LHG. Reservoirs should be constantly inspected to ensure integrity, and safety valves should be installed to relieve the LHG vapour generated at maximum heat load. Marine vessels are provided with fire suppression systems and have comprehensive emergency response procedures in place.
Crude oil and petroleum products marine vessels
Oil tankers and barges are vessels designed with the engines and quarters at the rear of the vessel and the remainder of the vessel divided into special compartments (tanks) to carry crude oil and liquid petroleum products in bulk. Cargo pumps are located in pump rooms, and forced ventilation and inerting systems are provided to reduce the risk of fires and explosions in pump rooms and cargo compartments. Modern oil tankers and barges are built with double hulls and other protective and safety features required by the United States Oil Pollution Act of 1990 and the
International Maritime Organization (IMO) tanker safety standards. Some new ship designs extend double hulls up the sides of the tankers to provide additional protection. Generally, large tankers carry crude oil and small tankers and barges carry petroleum products.
· Supertankers. Ultra-large and very large crude carriers (ULCCs and VLCCs) are restricted by their size and draft to specific routes of travel. ULCCs are vessels whose capacity is over 300,000 SDWTs, and VLCCs have capacities ranging from 160,000 to 300,000 SDWTs. Most large crude carriers are not owned by oil companies, but are chartered from transportation companies which specialize in operating these super-sized vessels.
· Oil tankers. Oil tankers are smaller than VLCCs, and, in addition to ocean travel, they can navigate restricted passages such as the Suez and Panama Canals, shallow coastal waters and estuaries. Large oil tankers, which range from 25,000 to 160,000 SDWTs, usually carry crude oil or heavy residual products. Smaller oil tankers, under 25,000 SDWT, usually carry gasoline, fuel oils and lubricants.
· Barges. Barges operate mainly in coastal and inland waterways and rivers, alone or in groups of two or more, and are either self-propelled or moved by tugboat. They may carry crude oil to refineries, but more often are used as an inexpensive means of transporting petroleum products from refineries to distribution terminals. Barges are also used to off-load cargo from tankers offshore whose draft or size does not allow them to come to the dock.
Barge and ship loading and unloading
Vessel-to-shore procedures, safety checklists and guidelines should be established and agreed upon by terminal and marine vessel operators. The International Safety Guide for Oil Tankers and Terminals (International Chamber of Shipping 1978) contains information and samples of checklists, guidelines, permits and other procedures covering safe operations when loading or unloading vessels, which may be used by vessel and terminal operators.
Although marine vessels sit in water and are thereby intrinsically grounded, there is a need to provide protection from static electricity which can build up during loading or unloading. This is accomplished by bonding or connecting metal objects on the dock or loading/unloading apparatus to the metal of the vessel. Bonding is also accomplished by use of conductive loading hose or piping. An electrostatic spark of ignitable intensity may also be generated when lowering equipment, thermometers or gauging devices into compartments immediately after loading; enough time must be allowed for the static charge to dissipate.
Ship-to-shore electric currents, which are different from static electricity, may be generated by cathodic protection of the vessel’s hull or dock, or by galvanic potential differences between the vessel and the shore. These currents also build up in metal loading/unloading apparatus. Insulating flanges may be installed within the length of the loading arm and at the point where flexible hoses connect to the shore pipeline system. When the connections are broken, there is no opportunity for a spark to jump from one metal surface to another.
All vessels and terminals need mutually agreed upon emergency response procedures in case of a fire or release of product, vapour or toxic gas. These must cover emergency operations, stopping product flow and emergency removal of a vessel from the dock. The plans should consider communications, fire-fighting, vapour cloud mitigation, mutual aid, rescue, clean-up and remediation measures.
Fire protection portable equipment and fixed systems should be in accord with government and company requirements and appropriate to the size, function, exposure potential and value of the
dock and wharf facilities. The International Safety Guide for Oil Tankers and Terminals (International Chamber of Shipping 1978) contains a sample fire notice which may be used as a guide by terminals for dock fire prevention.
Marine vessel health and safety
In addition to the usual maritime working hazards, transporting crude oil and flammable liquids by marine vessel creates a number of special health, safety and fire prevention situations. These include surging and expansion of liquid cargo, flammable vapour hazards during transport and when loading and unloading, possibility of pyrophoric ignition, toxic exposures to materials such as hydrogen sulphide and benzene and safety considerations when venting, flushing and cleaning compart-ments. The economics of operating modern tankers requires them to be at sea for extended periods of time with only short intervals in port to load or unload cargo. This, together with the fact that tankers are highly automated, creates unique mental and physical demands on the few crew members used to operate the vessels.
Fire and explosion protection
Emergency plans and procedures should be developed and implemented that are appropriate for the type of cargo on board and other potential hazards. Fire-fighting equipment must be supplied. Response team members who have shipboard fire-fighting, rescue and spill clean-up responsibilities should be trained, drilled and equipped to handle potential emergencies. Water, foam, dry chemicals, halon, carbon dioxide and steam are used as cooling, inhibiting and smothering fire-fighting agents aboard marine vessels, although halon is being phased out due to environmental concerns. The requirements for vessel fire-fighting equipment and systems are established by the country under whose flag the vessel sails and by company policy, but usually follow the recommendations of the 1974 International Convention for the Safety of Life at Sea (SOLAS).
Strict control of flames or naked lights, lighted smoking materials and other sources of ignition, such as welding or grinding sparks, electrical equipment and unprotected light bulbs, is required on vessels at all times to reduce the risk of fire and explosion. Prior to conducting hot work on board marine vessels, the area should be examined and tested to assure that conditions are safe, and permits should be issued for each specific task allowed.
One method of preventing explosions and fires in the vapour space of cargo compartments is to maintain the level of oxygen below 11% by making the atmosphere inert with a noncombustible gas. Sources for inert gas are exhaust gases from the vessel’s boilers or an independent gas generator or a gas turbine fitted with an afterburner. The 1974 SOLAS Convention implies that vessels carrying cargo with flashpoints below 60°C should have compartments fitted with inert systems. Vessels using inert gas systems should maintain cargo compartments in non-flammable conditions at all times. Inert gas compartments should be constantly monitored to assure safe conditions and should not be allowed to become flammable, because of the danger of ignition from pyrophoric deposits.
Confined spaces
Confined spaces on marine vessels, such as cargo compartments, paint lockers, pump rooms, fuel tanks and spaces between double hulls, must be treated the same as any confined space for entry, hot work and cold work. Tests for oxygen content, flammable vapours and toxic substances, in that order, must be conducted prior to entering confined spaces. A permit system should be established and followed for all confined space entry, safe (cold) work and hot work, which indicates safe exposure levels and required personal and respiratory protective equipment. In waters of the United States, these tests may be conducted by qualified individuals called “marine chemists”.
Compartments on marine vessels such as cargo tanks and pump rooms are confined spaces; when cleaning those which have been made inert or have flammable vapour, toxic or unknown atmospheres, they should be tested, and special safety and respiratory protection procedures should be followed. After crude oil has been unloaded, a small amount of residue, called clingage, remains on the interior surfaces of the compartments, which may then be washed and filled with water for ballast. One method of reducing the amount of residue is to install fixed equipment which removes up to 80% of the clingage by washing down the sides of inerted compartments with crude oil during unloading.
Pumps, valves and equipment
A work permit should be issued and safe work procedures followed, such as bonding, draining and vapour freeing, flammable vapour and toxic exposure testing, and providing stand-by fire protection equipment when operations, maintenance or repair requires opening cargo pumps, lines, valves or equipment on board marine vessels.
Toxic exposures
There is an opportunity for vented gases such as flue gas or hydrogen sulphide to reach the decks of vessels, even from specially designed vent systems. Testing should be continuously conducted to determine inert gas levels on all vessels and hydrogen sulphide levels on vessels which contain or previously carried sour crude oil or residual fuel. Tests should be conducted for benzene exposure on vessels carrying crude oil and gasoline. Inert gas scrubber effluent water and condensate water is acidic and corrosive; PPE should be used when contact is possible.
Environmental protection
Marine vessels and terminals should establish procedures and provide equipment to protect the environment from spills on water and land, and from releases of vapour to the air. The use of large vapour recovery systems at marine terminals is growing. Care must be taken to comply with air pollution requirements when vessels vent compartments and enclosed spaces. Emergency response procedures should be established, and equipment and trained personnel should be available to respond to spills and releases of crude oil and flammable and combustible liquids. A responsible person should be designated to ensure that notifications are made to both the company and the appropriate authorities should a reportable spill or release occur.
In the past, the oil-contaminated ballast water and tank washings were flushed out of the compartments at sea. In 1973, the International Convention for Prevention of Pollution from Ships established requirements that before the water is discharged at sea, the oily residue must be separated and retained on board for eventual onshore processing. Modern tankers have segregated ballast systems, with different lines, pumps and tanks than those used for cargo (in accordance with international recommen-dations), so that there is no possibility of contamination. Older vessels still carry ballast in cargo tanks, so special procedures, such as pumping oily water into designated onshore tanks and processing facilities, must be followed when discharging ballast in order to prevent pollution.
Motor Vehicle and Railroad Transport of Petroleum Products
Crude oil and petroleum products were initially transported by horse-drawn tank wagons, then by railroad tank cars and finally by motor vehicles. Following receipt at terminals from marine vessels or pipelines, bulk liquid petroleum products are delivered by non-pressure tank trucks or rail tank cars directly to service stations and consumers or to smaller terminals, called bulk plants, for
redistribution. LPG, gasoline anti-knock compounds, hydrofluoric acid and many other products, chemicals and additives used in the oil and gas industry are transported in pressure tank cars and tank trucks. Crude oil may also be transported by tank truck from small producing wells to gathering tanks, and by tank truck and railroad tank car from storage tanks to refineries or main pipelines. Packaged petroleum products in bulk bins or drums and pallets and cases of smaller containers are carried by package truck or railroad box car.
Government regulations
Transportation of petroleum products by motor vehicle or railroad tank car is regulated by government agencies throughout most of the world. Agencies such as the US DOT and the Canadian Transport Commission (CTC) have established regulations governing the design, construction, safety devices, testing, preventive maintenance, inspection and operation of tank trucks and tank cars. Regulations governing railroad tank car and tank truck operations typically include tank pressure and pressure relief device testing and certification before being placed into initial service and at regular intervals thereafter. The Association of American Railroads and the National Fire Protection Association (NFPA) are typical of organizations which publish specifications and requirements for the safe operation of tank cars and tank trucks. Most governments have regulations or adhere to United Nations Conventions which require the identification of and information concerning hazardous materials and petroleum products which are shipped in bulk or in containers. Railroad tank cars, tank trucks and package trucks are placarded to identify any hazardous products being transported and to provide emergency response information.
Railroad tank cars
Railroad tank cars are constructed of carbon steel or aluminium and may be pressurized or unpressurized. Modern tank cars can hold up to 171,000 l of compressed gas at pressures up to 600 psi (1.6 to 1.8 mPa). Non-pressure tank cars have evolved from small wooden tank cars of the late 1800s to jumbo tank cars which transport as much as 1.31 million litres of product at
pressures up to 100 psi (0.6 mPa). Non-pressure tank cars may be individual units with one or multiple compartments or a string of interconnected tank cars, called a tank train. Tank cars are loaded individually, and entire tank trains can be loaded and unloaded from a single point. Both pressure and non-pressure tank cars may be heated, cooled, insulated and thermally protected against fire, depending on their service and the products transported.
All railroad tank cars have top- or bottom-liquid or vapour valves for loading and unloading and hatch entries for cleaning. They are also equipped with devices intended to prevent the increase of internal pressure when exposed to abnormal con-ditions. These devices include safety relief valves held in place by a spring which can open to relieve pressure and then close; safety vents with rupture discs that burst open to relieve pressure but cannot reclose; or a combination of the two devices. A vacuum relief valve is provided for non-pressure tank cars to prevent vacuum formation when unloading from the bottom. Both pressure and non-pressure tank cars have protective housings on top surrounding the loading connections, sample lines, thermometer wells and gauging devices. Platforms for loaders may or may not be provided on top of cars. Older nonpressure tank cars may have one or more expansion domes. Fittings are provided on the bottom of tank cars for unloading or cleaning. Head shields are provided on the ends of tank cars to prevent puncture of the shell by the coupler of another car during derailments.
LNG is shipped as a cryogenic gas in insulated tank truck and rail pressure tank cars. Pressure tank trucks and rail tank cars for LNG transport have a stainless steel inner reservoir suspended in an outer reservoir of carbon steel. The annular space is a vacuum filled with insulation to maintain low temperatures during shipment. To prevent gas from igniting back to the tanks, they are equipped with two independent, remotely controlled fail-safe emergency shut-off valves on the filling and discharge lines and have gauges on both the inside and outside reservoirs.
LPG is transported on land in specially designed rail tank cars (up to 130 capacity) or tank trucks (up to 40 capacity). Tank trucks and rail tank cars for LPG transport are typically uninsulated steel
cylinders with spherical bottoms, equipped with gauges, thermometers, two safety relief valves, a gas level meter and maximum fill indicator and baffles.
Rail tank cars transporting LNG or LPG should not be overloaded, since they may sit on a siding for some period of time and be exposed to high ambient temperatures, which could cause overpressure and venting. Bond wires and grounding cables are provided at rail and tank truck loading racks to help neutralize and dissipate static electricity. They should be connected before operations commence and not disconnected until operations are complete and all valves are closed. Truck and rail loading facilities are typically protected by fire water spray or mist systems and fire extinguishers.
Tank trucks
Petroleum products and crude oil tank trucks are typically constructed of carbon steel, aluminium or a plasticized fibreglass material, and vary in size from 1,900-l tank wagons to jumbo 53,200-l tankers. The capacity of tank trucks is governed by regulatory agencies, and usually is dependent upon highway and bridge capacity limitations and the allowable weight per axle or total amount of product allowed.
There are pressurized and non-pressurized tank trucks, which may be non-insulated or insulated depending on their service and the products transported. Pressurized tank trucks are usually single compartment, and non-pressurized tank trucks may have single or multiple compartments. Regardless of the number of compartments on a tank truck, each compartment must be treated individually, with its own loading, unloading and safety-relief devices. Compartments may be separated by single or double walls. Regulations may require that incompatible products and flammable and combustible liquids carried in different compartments on the same vehicle be
separated by double walls. When pressure testing compartments, the space between the walls should also be tested for liquid or vapour.
Tank trucks have either hatches which open for top loading, valves for closed top- or bottomloading and unloading, or both. All compartments have hatch entries for cleaning and are equipped with safety relief devices to mitigate internal pressure when exposed to abnormal conditions. These devices include safety relief valves held in place by a spring which can open to relieve pressure and then close, hatches on non-pressure tanks which pop open if the relief valves fail and rupture discs on pressurized tank trucks. A vacuum relief valve is provided for each nonpressurized tank truck compartment to prevent vacuum when unloading from the bottom. Nonpressurized tank trucks have railings on top to protect the hatches, relief valves and vapour recovery system in case of a rollover. Tank trucks are usually equipped with breakaway, selfclosing devices installed on compartment bottom loading and unloading pipes and fittings to prevent spills in case of damage in a rollover or collision.
Rail tank car and tank truck loading and unloading
While railroad tank cars are almost always loaded and unloaded by workers assigned to these specific duties, tank trucks may be loaded and unloaded by either loaders or drivers. Tank cars and tank trucks are loaded at facilities called loading racks, and may be top loaded through open hatches or closed connections, bottom loaded through closed connections, or a combination of both.
Loading
Workers who load and unload crude oil, LPG, petroleum products, and acids and additives used in the oil and gas industry, should have a basic understanding of the characteristics of the products handled, their hazards and exposures and the operating procedures and work practices needed to perform the job safely. Many government agencies and companies require the use and completion of inspection forms upon receipt and shipment and prior to loading and unloading railroad tank cars and tank trucks. Tank trucks and railroad tank cars may be loaded through open hatches on the top or through fittings and valves at the top or bottom of each tank or compartment. Closed connections are required when pressure loading and where vapour recovery systems are provided. If loading systems do not activate for any reason (such as improper operation of the vapour recovery system or a fault in the grounding or bonding system), by-pass should not be attempted without approval. All hatches should be closed and securely latched during transit.
Workers should follow safe work practices to avoid slips and falls when top loading. If loading controls use pre-set meters, loaders must be careful to load the correct products into the assigned tanks and compartments. All compartment hatches should be shut when bottom loading, and when top loading, only the compartment being loaded should be open. When top loading, splash loading should be avoided by placing the loading tube or hose close to the bottom of the compartment and starting to load slowly until the opening is submerged. During manual top loading operations, loaders should remain in attendance, not tie down the loading shut-off (deadman) control and not overfill the compartment. Loaders should avoid exposures to product and vapour by standing upwind and averting the head when top loading through open hatches and by wearing protective equipment when handling additives, obtaining samples and draining hoses. Loaders should be aware of and follow prescribed response actions in case of a hose or line rupture, spill, release, fire or other emergency.
Unloading and delivery
When unloading tank cars and tank trucks, it is important first to assure that each product is unloaded into the proper designated storage tank and that the tank has sufficient capacity to hold all of the product being delivered. Although valves, fill pipes, lines and fill covers should be colour coded or otherwise marked to identify the product contained, the driver should still be responsible
for product quality during delivery. Any misdelivery of product, mixing or contamination should be immediately reported to the recipient and to the company to prevent serious consequences. When drivers or operators are required to additize products or obtain samples from storage tanks following delivery to assure product quality or for any other reason, all safety and health provisions specific to the exposure should be followed. Persons engaged in delivery and unloading operations should remain in the vicinity at all times and know what to do in an emergency, including notification, stopping product flow, cleaning spills and when to leave the area.
Pressurized tanks may be unloaded by compressor or pump, and unpressurized tanks by gravity, vehicle pump or recipient pump. Tank trucks and tank cars which carry lubrication or industrial oils, additives and acids are sometimes unloaded by pressurizing the tank with an inert gas such as nitrogen. Tank cars or tank trucks may need to be heated using steam or electric coils in order to unload heavy crude oils, viscous products and waxes. All of these activities have inherent dangers and exposures. Where required by regulation, unloading should not commence until the vapour recovery hoses have been connected between the delivery tank and the storage tank. When delivering petroleum products to residences, farms and commercial accounts, drivers should gauge any tank which is not equipped with a vent alarm in order to prevent an overfill.
Loading-rack fire protection
Fires and explosions at top and bottom tank car and tank truck loading racks may occur from causes such as electrostatic build-up and incendiary spark discharge in a flammable atmosphere, unauthorized hot work, flashback from a vapour recovery unit, smoking or other unsafe practices.
Sources of ignition, such as smoking, running internal combustion engines and hot work activity, should be controlled at the loading rack at all times, and particularly during loading or other operations when a spill or release may occur. Loading racks may be equipped with portable fire
extinguishers and manually or automatically operated foam, water or dry chemical fire extinguishing systems. If vapour recovery systems are in use, flame arrestors should be provided to prevent flashback from the recovery unit to the loading rack.
Drainage should be provided at loading racks to divert product spills away from the loader, tank truck or tank car and the loading rack pad. Drains should be provided with fire traps to prevent migration of flames and vapours through sewer systems. Other loading-rack safety considerations include emergency shut-down controls placed at loading spots and other strategic locations in the terminal and automatic pressure-sensing valves which stop product flow to the rack in case of a leak in the product lines. Some companies have installed automatic brake lock systems on their tank truck fill connections, which lock the brakes and will not allow the truck to be moved from the rack until the fill lines have been disconnected.
Electrostatic ignition hazards
Some products such as intermediate distillates and low-vapour-pressure fuels and solvents tend to accumulate electrostatic charges. When loading tank cars and tank trucks, there is always an opportunity for electrostatic charges to be generated by friction as product goes through lines and filters and by splash loading. This can be mitigated by designing loading racks to allow for relaxation time in piping downstream from pumps and filters. Compartments should be checked to assure that they do not contain any unbonded or floating objects which could act as static accumulators. Bottom loaded compartments may be provided with internal cables to help dissipate electrostatic charges. Sample containers, thermometers or other items should not be lowered into compartments until a waiting period of at least 1 minute has elapsed, to allow any electrostatic charge which has accumulated in the product to dissipate.
Bonding and grounding are important considerations in dissipating electrostatic charges which build up during loading operations. By keeping the fill pipe in contact with the metal side of the hatch when top loading, and through the use of metal loading arms or conductive hose when loading through closed connections, the tank truck or tank car is bonded to the loading rack, maintaining the same electrical charge between the objects so that a spark is not created when the loading tube or hose is removed. The tank car or tank truck may also be bonded to the loading rack by use of a bonding cable, which carries any accumulated charge from a terminal on the tank to the rack, where it is then grounded by a grounding cable and rod. Similar bonding precautions are needed when unloading from tank cars and tank trucks. Some loading racks are provided with electronic connectors and sensors which will not allow loading pumps to activate until a positive bond is achieved.
During cleaning, maintenance or repair, pressurized LPG tank cars or tank trucks are usually opened to the atmosphere, allowing air to enter the tank. In order to prevent combustion from electrostatic charges when loading these cars for the first time after such activities, it is necessary to reduce the oxygen level below 9.5% by blanketing the tank with inert gas, such as nitrogen. Precautions are needed to prevent liquid nitrogen from entering the tank if the nitrogen is provided from portable containers.
Switch loading
Switch loading occurs when intermediate- or low-vapour-pressure products such as diesel fuel or fuel oil are loaded into a tank car or tank truck compartment which previously contained a flammable product such as gasoline. The electrostatic charge generated during loading can discharge in an atmosphere which is within the flammable range, with a resultant explosion and fire. This hazard can be controlled when top loading by lowering the fill tube to the bottom of the compartment and loading slowly until the end of the tube is submerged to avoid splash loading or agitation. Metal to metal contact should be maintained during loading in order to provide a positive bond between the loading tube and the tank hatchway. When bottom loading, initial slow fill or splash deflectors are used to reduce static build-up. Prior to switch loading, tanks which
cannot be drained dry may be flushed out with a small amount of the product to be loaded, to remove any flammable residue in sumps, lines, valves and onboard pumps.
Shipping products by rail box cars and package vans
Petroleum products are shipped by motor truck package vans and railroad box cars in metal, fibre and plastic containers of various sizes, from 55-gallon (209-l) drums to 5-gallon (19-l) pails and from 2-1/2-gallon (9.5-l) to 1-quart (.95-l) containers, in corrugated boxes, usually on pallets. Many industrial and commercial petroleum products are shipped in large metal, plastic or combination intermediate bulk containers ranging in size from 380 to over 2,660 l capacity. LPG is shipped in large and small pressure containers. In addition, samples of crude oil, finished products and used products are shipped by mail or express freight carrier to laboratories for assay and analysis.
All of these products, containers and packages have to be handled in accordance with government regulations for hazardous chemicals, flammable and combustible liquids and toxic materials. This requires the use of hazardous materials manifests, shipping documents, permits, receipts and other regulatory requirements, such as marking the outsides of packages, containers, motor trucks and box cars with proper identification and a hazard warning label. Proper utilization of tank trucks and tank cars is important to the petroleum industry. Because storage capacity is finite, delivery schedules need to be met, from the delivery of crude oil to keep refineries running to the delivery of gasoline to service stations, and from the delivery of lubricants to commercial and industrial accounts to the delivery of heating oil to homes.
LPG is supplied to consumers by bulk tank trucks which pump directly into smaller onsite storage tanks, both above ground and below ground (e.g., service stations, farms, commercial and industrial consumers). LPG is also delivered to consumers by truck or van in containers (gas cylinders or bottles). LNG is delivered in special cryogenic containers which have an inner fuel tank
surrounded by insulation and an outer shell. Similar containers are provided for vehicles and appliances which use LNG as a fuel. Compressed natural gas is normally delivered in conventional compressed gas cylinders, such as those used on industrial lift trucks.
In addition to the normal safety and health precautions required in rail car and package trucking operations, such as moving and handling heavy objects and operating industrial trucks, workers should be familiar with the hazards of the products they are handling and delivering, and know what to do in case of a spill, release or other emergency. For example, intermediate bulk containers and drums should not be dropped out of box cars or from the tailgates of trucks onto the ground. Both companies and government agencies have established special regulations and requirements for drivers and operators who are involved in the transport and delivery of flammable and hazardous petroleum products.
Tank truck and package van drivers often work alone and may have to travel great distances for a number of days to deliver their loads. They work both day and night and in all sorts of weather conditions. Manoeuvring super-sized tank trucks into service stations and customer locations without hitting parked vehicles or fixed objects requires patience, skill and experience. Drivers should have the physical and mental characteristics required for this work.
Driving tank trucks is different from driving package vans in that the liquid product tends to shift forward as the truck stops, backwards as the truck accelerates and from side to side as the truck turns. Tank truck compartments should be fitted with baffles which restrict the movement of product during transport. Considerable skill is required by drivers to overcome the inertia created by this phenomenon, called “mass in motion”. Occasionally, tank truck drivers are required to pump out storage tanks. This activity requires special equipment, including suction hose and transfer pumps, and safety precautions, such as bonding and grounding to dissipate electrostatic build-up and to prevent any release of vapours or liquids.
Motor vehicle and rail car emergency response
Drivers and operators should be familiar with notification requirements and emergency response actions in case of a fire or a release of product, gas or vapour. Product identification and hazard warning placards in compliance with industry, association or national marking standards are posted on trucks and rail cars to allow emergency responders to determine the precautions needed in case of a spill or release of vapour, gas or product. Motor vehicle drivers and train operators may also be required to carry material safety data sheets (MSDSs) or other documentation describing the hazards and precautions for handling the products being transported. Some companies or government agencies require that vehicles transporting flammable liquids or hazardous materials carry first aid kits, fire extinguishers, spill clean-up materials and portable hazard warning devices or signals to alert motorists if the vehicle is stopped alongside a highway.
Special equipment and techniques are required if a tank car or tank truck needs to be emptied of product as the result of an accident or rollover. Removal of product through fixed piping and valves or by using special knock-out plates on tank truck hatches is preferred; however, under certain conditions holes may be drilled in tanks using prescribed safe work procedures. Regardless of the method of removal, tanks should be grounded and a bond connection provided between the tank being emptied and the receiving tank.
Cleaning tank cars and tank trucks
Entering a tank car or tank truck compartment for inspection, cleaning, maintenance or repair is a hazardous activity requiring that all ventilation, testing, gas freeing and other confined-space entry
and permit system requirements be followed in order to assure a safe operation. Cleaning tank cars and tank trucks is not any different from cleaning petroleum-product storage tanks, and all the same safety and health exposure precautions and procedures apply. Tank cars and tank trucks may contain residue of flammable, hazardous or toxic materials in sumps and unloading piping, or have been unloaded using an inert gas, such as nitrogen, so that what may appear to be a clean, safe space is not. Tanks which have contained crude oil, residues, asphalt or high-melting-point products may need to be steam or chemically cleaned prior to ventilation and entry, or may have a pyrophoric hazard. Ventilating tanks to free them from vapours and toxic or inert gases may be accomplished by opening the lowest and furthest valve or connection on each tank or compartment and placing an air eductor at the furthest top opening. Monitoring should be performed prior to entry without respiratory protection to assure that all of the corners and low spots in the tank, such as sumps, have been thoroughly vented, and ventilation should continue while working in the tank.
Aboveground Tank Storage of Liquid Petroleum Products
Crude oil, gas, LNG and LPG, processing additives, chemicals and petroleum products are stored in aboveground and underground atmospheric (non-pressure) and pressure storage tanks. Storage tanks are located at the ends of feeder lines and gathering lines, along truck pipelines, at marine loading and unloading facilities and in refineries, terminals and bulk plants. This section covers aboveground atmospheric storage tanks in refinery, terminal and bulk plant tank farms. (Information concerning aboveground pressure tanks is covered below, and information concerning underground tanks and small aboveground tanks is in the article “Motor vehicle fuelling and servicing operations”.)
Terminals and bulk plants
Terminals are storage facilities which generally receive crude oil and petroleum products by trunk pipeline or marine vessel. Terminals store and redistribute crude oil and petroleum products to refineries, other terminals, bulk plants, service stations and consumers by pipelines, marine
vessels, railroad tank cars and tank trucks. Terminals may be owned and operated by oil companies, pipeline companies, independent terminal operators, large industrial or commercial consumers or petroleum product distributors.
Bulk plants are usually smaller than terminals and typically receive petroleum products by rail tank car or tank truck, normally from terminals but occasionally direct from refineries. Bulk plants store and redistribute products to service stations and consumers by tank truck or tank wagon (small tank trucks of approximately 9,500 to 1,900 l capacity). Bulk plants may be operated by oil companies, distributors or independent owners.
Tank farms
Tank farms are groupings of storage tanks at producing fields, refineries, marine, pipeline and distribution terminals and bulk plants which store crude oil and petroleum products. Within tank farms, individual tanks or groups of two or more tanks are usually surrounded by enclosures called berms, dykes or fire walls. These tank farm enclosures may vary in construction and height, from 45-cm earth berms around piping and pumps inside dykes to concrete walls that are taller than the tanks they surround. Dykes may be built of earth, clay or other materials; they are covered with gravel, limestone or sea shells to control erosion; they vary in height and are wide enough for vehicles to drive along the top. The primary functions of these enclosures are to contain, direct and divert rain water, physically separate tanks to prevent the spread of fire in one area to another, and to contain a spill, release, leak or overflow from a tank, pump or pipe within the area.
Dyke enclosures may be required by regulation or company policy to be sized and maintained to hold a specific amount of product. For example, a dyke enclosure may need to contain at least 110% of the capacity of the largest tank therein, allowing for the volume displaced by the other tanks and the amount of product remaining in the largest tank after hydrostatic equilibrium is
reached. Dyke enclosures may also be required to be constructed with impervious clay or plastic liners to prevent spilled or released product from contaminating soil or groundwater.
Storage tanks
There are a number of different types of vertical and horizontal aboveground atmospheric and pressure storage tanks in tank farms, which contain crude oil, petroleum feedstocks, intermediate stocks or finished petroleum products. Their size, shape, design, configuration, and operation depend on the amount and type of products stored and company or regulatory requirements. Aboveground vertical tanks may be provided with double bottoms to prevent leakage onto the ground and cathodic protection to minimize corrosion. Horizontal tanks may be constructed with double walls or placed in vaults to contain any leakage.
Atmospheric cone roof tanks
Cone roof tanks are aboveground, horizontal or vertical, covered, cylindrical atmospheric vessels. Cone roof tanks have external stairways or ladders and platforms, and weak roof to shell seams, vents, scuppers or overflow outlets; they may have appurtenances such as gauging tubes, foam piping and chambers, overflow sensing and signalling systems, automatic gauging systems and so on.
When volatile crude oil and flammable liquid petroleum products are stored in cone roof tanks there is an opportunity for the vapour space to be within the flammable range. Although the space between the top of the product and the tank roof is normally vapour rich, an atmosphere in the flammable range can occur when product is first put into an empty tank or as air enters the tank
through vents or pressure/vacuum valves when product is withdrawn and as the tank breathes during temperature changes. Cone roof tanks may be connected to vapour recovery systems.
Conservation tanks are a type of cone roof tank with an upper and lower section separated by a flexible membrane designed to contain any vapour produced when the product warms up and expands due to exposure to sunlight in the daytime and to return the vapour to the tank when it condenses as the tank cools down at night. Conservation tanks are typically used to store aviation gasoline and similar products.
Atmospheric floating roof tanks
Floating roof tanks are aboveground, vertical, open top or covered cylindrical atmospheric vessels that are equipped with floating roofs. The primary purpose of the floating roof is to minimize the vapour space between the top of the product and the bottom of the floating roof so that it is always vapour rich, thus precluding the chance of a vapour-air mixture in the flammable range. All floating roof tanks have external stairways or ladders and platforms, adjustable stairways or ladders for access to the floating roof from the platform, and may have appurtenances such as shunts which electrically bond the roof to the shell, gauging tubes, foam piping and chambers, overflow sensing and signalling systems, automatic gauging systems and so on. Seals or boots are provided around the perimeter of floating roofs to prevent product or vapour from escaping and collecting on the roof or in the space above the roof.
Floating roofs are provided with legs which may be set in high or low positions depending on the type of operation. Legs are normally maintained in the low position so that the greatest possible amount of product can be withdrawn from the tank without creating a vapour space between the top of the product and the bottom of the floating roof. As tanks are brought out of service prior to entry for inspection, maintenance, repair or cleaning, there is a need to adjust the roof legs into
the high position to allow room to work under the roof once the tank is empty. When the tank is returned to service, the legs are readjusted into the low position after it is filled with product.
Aboveground floating roof storage tanks are further classified as external floating roof tanks, internal floating roof tanks or covered external floating roof tanks.
External (open top) floating roof tanks are those with floating covers installed on open-top storage tanks. External floating roofs are usually constructed of steel and provided with pontoons or other means of flotation. They are equipped with roof drains to remove water, boots or seals to prevent vapour releases and adjustable stairways to reach the roof from the top of the tank regardless of its position. They may also have secondary seals to minimize release of vapour to the atmosphere, weather shields to protect the seals and foam dams to contain foam in the seal area in case of a fire or seal leak. Entry onto external floating roofs for gauging, maintenance or other activities may be considered confined-space entry, depending on the level of the roof below the top of the tank, the products contained in the tank and government regulations and company policy.
Internal floating roof tanks usually are cone roof tanks which have been converted by installing buoyant decks, rafts or internal floating covers inside the tank. Internal floating roofs are typically constructed of various types of sheet metal, aluminium, plastic or metal-covered plastic expanded foam, and their construction may be of the pontoon or pan type, solid buoyant material, or a combination of these. Internal floating roofs are provided with perimeter seals to prevent vapour from escaping into the portion of the tank between the top of the floating roof and the exterior roof. Pressure/vacuum valves or vents are usually provided at the top of the tank to control any hydrocarbon vapours which may accumulate in the space above the internal floater. Internal floating roof tanks have ladders installed for access from the cone roof to the floating roof. Entry onto internal floating roofs for any purpose should be considered confined-space entry.
Covered (external) floating roof tanks are basically external floating roof tanks that have been retrofitted with a geodesic dome, snow cap or similar semi-fixed cover or roof so that the floating roof is no longer open to the atmosphere. Newly constructed covered external floating roof tanks may incorporate typical floating roofs designed for internal floating roof tanks. Entry onto covered external floating roofs for gauging, maintenance or other activities may be considered confinedspace entry, depending on the construction of the dome or cover, the level of the roof below the top of the tank, the products contained in the tank and government regulations and company policy.
Pipeline and marine receipts
An important safety, product quality and environmental concern in tank storage facilities is to prevent intermixing of products and overfilling tanks by developing and implementing safe operating procedures and work practices. Safe operation of storage tanks depends on receiving product into tanks within their defined capacity by designating receiving tanks prior to delivery, gauging tanks to determine the available capacity and ensuring that valves are properly aligned and that only the receiving tank inlet is opened, so the correct amount of product is delivered into the assigned tank. Drains in dyke areas surrounding tanks receiving product should normally be kept closed during receipt in case an overfill or spill occurs. Overfill protection and prevention can be accomplished by a variety of safe operating practices, including manual controls and automatic detection, signalling and shut-down systems and a means of communication, all of which should be mutually understood and acceptable to product transfer personnel at the pipeline, marine vessel and terminal or refinery.
Government regulations or company policy may require that automatic product level detection devices and signal and shut-down systems be installed on tanks receiving flammable liquids and other products from trunk pipelines or marine vessels. Where such systems are installed, electronic system integrity tests should be conducted on a regular basis or prior to product
transfer, and if the system fails, transfers should follow manual receipt procedures. Receipts should be monitored manually or automatically, onsite or from a remote control location, to ensure that operations are proceeding as planned. Upon completion of transfer, all valves should be returned to normal operating position or set for the next receipt. Pumps, valves, pipe connections, bleeder and sample lines, manifold areas, drains and sumps should be inspected and maintained to assure good condition and to prevent spills and leakage.
Tank gauging and sampling
Tank storage facilities should establish procedures and safe work practices for gauging and sampling crude oil and petroleum products which take into consideration the potential hazards involved with each product stored and each type of tank in the facility. Although tank gauging is often done using automatic mechanical or electronic devices, manual gauging should be performed at scheduled intervals to assure the accuracy of the automatic systems.
Manual gauging and sampling operations usually require the operator to climb to the top of the tank. When gauging floating roof tanks, the operator then has to descend onto the floating roof unless the tank is fitted with gauging and sampling tubes that are accessible from the platform. With cone roof tanks, the gauger must open a roof hatch in order to lower the gauge into the tank. Gaugers should be aware of the confined-space entry requirements and potential hazards when entering onto covered floating roofs or down upon open-top floating roofs which are below established height levels. This may require the use of monitoring devices, such as oxygen, combustible gas and hydrogen sulphide detectors and personal and respiratory protective equipment.
Product temperatures and samples may be taken at the same time as manual gauging is conducted. Temperatures may also be recorded automatically and samples obtained from built-in
sample connections. Manual gauging and sampling should be restricted while tanks are receiving product. Following the completion of receipt, a relaxation period of from 30 minutes to 4 hours, depending on the product and company policy, should be required to allow any electrostatic buildup to dissipate before conducting manual sampling or gauging. Some companies require that communications or visual contact be established and maintained between gaugers and other facility personnel when descending upon floating roofs. Entry onto tank roofs or platforms for gauging, sampling or other activities should be restricted during thunderstorms.
Tank venting and cleaning
Storage tanks are taken out of service for inspection, testing, maintenance, repair, retrofitting and tank cleaning as needed or at regular intervals dependent on government regulations, company policy and operating service requirements. Although tank venting, cleaning and entry is a potentially hazardous operation, this work can be accomplished without incident, provided that proper procedures are established and safe work practices followed. Without such precautions, injury or damage can occur from explosions, fires, lack of oxygen, toxic exposures and physical hazards.
Preliminary preparations
A number of preliminary preparations are required after it has been decided that a tank needs to be taken out of service for inspection, maintenance or cleaning. These include: scheduling storage and supply alternatives; reviewing the tank history to determine whether it has ever contained leaded product or has previously been cleaned and certified lead free; determining the amount and type of products contained and how much residue will remain in the tank; inspecting the outside of the tank, the surrounding area and the equipment to be used for product removal, vapour freeing and cleaning; assuring that personnel are trained, qualified and familiar with facility permit and safety procedures; assigning job responsibilities in accordance with the facility’s confined-space entry and hot- and safe-work permit requirements; and holding a meeting
between terminal and tank cleaning personnel or contractors before tank cleaning or construction starts.
Control of ignition sources
After the removal of all available product from the tank through fixed piping, and before any water draws or sample lines are opened, all sources of ignition should be removed from the surrounding area until the tank is declared vapour free. Vacuum trucks, compressors, pumps and other equipment which is electrically or motor driven should be located upwind, either on top of or outside the dyke area, or, if inside the dyke area, at least 20 m from the tank or any other sources of flammable vapours. Tank preparation, venting and cleaning activities should cease during electrical storms.
Removing residue
The next step is to remove as much remaining product or residue in the tank as possible through pipeline and waterdraw connections. A safe-work permit may be issued for this work. Water or distillate fuel may be injected into the tank through fixed connections to help float product out of the tank. Residue removed from tanks that have contained sour crude should be kept wet until disposal to avoid spontaneous combustion.
Isolating the tank
After all available product has been removed through fixed piping, all piping connected to the tank, including product lines, vapour recovery lines, foam piping, sample lines and so on, should be disconnected by closing the valves nearest the tank and inserting blinds in the lines on the tank side of the valve to prevent any vapours from entering the tank from the lines. The portion of piping between the blinds and the tank should be drained and flushed. Valves outside the dyke area should be closed and locked or tagged. Tank pumps, internal mixers, cathodic protection systems, electronic gauging and level detection systems and so on should be disconnected, deenergized and locked or tagged out.
Vapour freeing
The tank is now ready to be made vapour free. Intermittent or continuous vapour testing should be conducted and work in the area restricted during tank ventilation. Natural ventilation, through opening the tank to the atmosphere, is not usually preferred, since it is neither as fast nor as safe as forced ventilation. There are a number of methods of mechanically venting a tank, depending on its size, construction, condition and internal configuration. In one method, cone roof tanks may be vapour freed by placing an eductor (a portable ventilator) at a hatch on the top of the tank, starting it slowly while a hatch at the bottom of the tank is opened and then setting it on high speed to draw air and vapours through the tank.
A safe- or hot-work permit should be issued covering ventilation activities. All blowers and eductors should be securely bonded to the tank shell to prevent electrostatic ignition. For safety purposes, blowers and eductors should preferably be operated by compressed air; however, explosion-proof electric- or steam-driven motors have been used. Internal floating roof tanks may need to have the portions above and below the floating roof vented separately. If vapours are discharged from a bottom hatch, a vertical tube at least 4 m above ground level and no lower than the surrounding dyke wall is needed in order to prevent vapours from collecting at low levels or reaching a source of ignition before dissipating. If necessary, vapours may be directed to the facility vapour recovery system.
As ventilation progresses, the remaining residue can be washed down and removed through the open bottom hatch by water and suction hoses, both of which should be bonded to the tank shell to prevent electrostatic ignition. Tanks which have contained sour crude oil or high-sulphur residual products may generate spontaneous heat and ignite as they dry out during ventilation. This should be avoided by wetting the inside of the tank with water to blanket the deposits from air and prevent a rise in temperature. Any iron sulphide residue should be removed from the open hatch to prevent ignition of vapours during ventilation. Workers engaged in washdown, removal and wetting activities should wear appropriate personal and respiratory protection.
Initial entry, inspection and certification
An indication of the progress being made in vapour freeing the tank can be obtained by monitoring vapours at the point of eduction during ventilation. Once it appears that the flammable vapour level is below that established by regulatory agencies or company policy, entry can be made into the tank for inspection and testing purposes. The entrant should wear appropriate personal and air-supplied respiratory protection; after testing the atmosphere at the hatch and obtaining an entry permit, the worker may enter the tank to continue testing and inspection. Checks for obstructions, falling roofs, weak supports, holes in the floor and other physical hazards should be conducted during the inspection.
Cleaning, maintenance and repair
As ventilation continues and the vapour levels in the tank drop lower, permits may be issued allowing entry by workers with appropriate personal and respiratory equipment, if needed, to start cleaning the tank. Monitoring for oxygen, flammable vapours and toxic atmospheres should continue, and if the levels inside the tank exceed those established for entry, the permit should automatically expire and the entrants should immediately leave the tank until the safe level is
again achieved and the permit is reissued. Ventilation should continue during cleaning operations as long as any residue or sludge remains in the tank. Only low-voltage lighting or approved flashlights should be used during inspection and clean-up.
After tanks have been cleaned and dried, a final inspection and testing should be conducted before maintenance, repair or retrofitting work is started. Careful inspection of sumps, wells, floor plates, floating roof pontoons, supports and columns is needed to assure that no leaks have developed which allowed product to enter these spaces or seep beneath the floor. Spaces between foam seals and weather shields or secondary containment should also be inspected and tested for vapours. If the tank has previously contained leaded gasoline, or if no tank history is available, a lead-in-air test should be conducted and the tank certified lead free before workers are allowed inside without air-supplied respiratory equipment.
A hot-work permit should be issued covering welding, cutting and other hot work, and a safe-work permit issued to cover other repair and maintenance activities. Welding or hot work can create toxic or noxious fumes inside the tank, requiring monitoring, respiratory protection and continued ventilation. When tanks are to be retrofitted with double bottoms or internal floating roofs, a large hole is often cut into the side of the tank to provide unrestricted access and avoid the need for confined-space entry permits.
Blast cleaning and painting the outside of tanks usually follows tank cleaning and is completed before the tank is returned to service. These activities, together with cleaning and painting tank farm piping, may be performed while tanks and pipes are in service, by implementing and following prescribed safety procedures, such as conducting monitoring for hydrocarbon vapours and stopping blast cleaning while nearby tanks are receiving flammable liquid products. Blast cleaning with sand has the potential for hazardous exposure to silica; therefore, many government agencies and companies require the use of special non-toxic blast cleaning materials or grit, which may be collected, cleaned and recycled. Special vacuum collection blast cleaning devices may be
used in order to avoid contamination when cleaning leaded paint from tanks and piping. Following blast cleaning, spots in the tank walls or piping suspected of having leaks and seeps should be tested and repaired before being painted.
Returning the tank to service
In preparation for return to service upon completion of tank cleaning, inspection, maintenance or repair, the hatches are closed, all blinds are removed and the piping is reconnected to the tank. Valves are unlocked, opened and aligned, and mechanical and electrical devices are reactivated. Many government agencies and companies require tanks to be hydrostatically tested to assure that there are no leaks before they are returned to service. Since a considerable amount of water is required to obtain the necessary pressure head for an accurate test, a water bottom topped with diesel fuel is often used. Upon completion of the testing, the tank is emptied and made ready to receive product. After receipt is completed and a relaxation time has elapsed, the legs on floating roof tanks are reset into the low position.
Fire protection and prevention
Whenever hydrocarbons are present in closed containers such as storage tanks in refineries, terminals and bulk plants, the potential exists for release of liquids and vapours. These vapours could mix with air in the flammable range and, if subjected to a source of ignition, cause an explosion or fire. Regardless of the capability of fire protection systems and personnel in the facility, the key to fire protection is fire prevention. Spills and releases should be stopped from entering sewers and drainage systems. Small spills should be covered with wet blankets, and larger spills with foam, to prevent vapours from escaping and mixing with air. Sources of ignition in areas when hydrocarbon vapours may be present should be eliminated or controlled. Portable fire extinguishers should be carried on service vehicles and located at accessible and strategic positions throughout the facility.
The establishment and implementation of safe work procedures and practices such as hot- and safe- (cold-) work permit systems, electrical classification programmes, lockout/tagout programmes, and employee and contractor training and education is critical to preventing fires. Facilities should develop preplanned emergency procedures, and employees should be knowledgeable in their responsibilities for reporting and responding to fires and evacuation. Telephone numbers of responsible persons and agencies to be notified in case of an emergency should be posted at the facility and a means of communication provided. Local fire departments, emergency response, public safety and mutual aid organizations should also be aware of the procedures and familiar with the facility and its hazards.
Hydrocarbon fires are controlled by one or a combination of methods, as follows:
· Removing fuel. One of the best and easiest methods of controlling and extinguishing a hydrocarbon fire is to shut off the source of fuel by closing a valve, diverting product flow or, if a small amount of product is involved, controlling exposures while allowing the product to burn away. Foam may also be used to cover hydrocarbon spills to prevent vapours from being emitted and mixing with the air.
· Removing oxygen. Another method is to shut off the supply of air or oxygen by smothering fires with foam or water fog, or by using carbon dioxide or nitrogen to displace air in enclosed spaces.
· Cooling. Water fog, mist or spray and carbon dioxide may be used to extinguish certain petroleum product fires by cooling the temperature of the fire below the product’s ignition temperature and by stopping vapours from forming and mixing with air.
· Interrupting combustion. Chemicals such as dry powders and halon extinguish fires by interrupting the chemical reaction of the fire.
Storage tank fire protection
Storage tank fire protection and prevention is a specialized science which depends on the interrelationship of tank type, condition and size; product and amount stored in the tank; tank spacing, dyking and drainage; facility fire protection and response capabilities; outside assistance; and company philosophy, industry standards and government regulations. Storage tank fires may be easy or very difficult to control and extinguish, depending primarily on whether the fire is detected and attacked during its initial inception. Storage tank operators should refer to the numerous recommended practices and standards developed by organizations such as the American Petroleum Institute (API) and the US National Fire Protection Association (NFPA), which cover storage tank fire prevention and protection in great detail.
If open-top floating roof storage tanks are out of round or if the seals are worn or not tight against the tank shells, vapours can escape and mix with air, forming flammable mixtures. In such situations, when lightning strikes, fires may occur at the point where the roof seals meet the shell of the tank. If detected early, small seal fires can often be extinguished by a hand-carried dry powder extinguisher or with foam applied from a foam hose or foam system.
If a seal fire cannot be controlled with hand extinguishers or hose streams, or if a large fire is in progress, foam may be applied onto the roof through fixed or semi-fixed systems or by large foam monitors. Precautions are necessary when applying foam onto the roofs of floating roof tanks; if too much weight is placed on the roof, it may tilt or sink, allowing a large surface area of product to be exposed and become involved in the fire. Foam dams are used on floating roof tanks to trap foam in the area between the seals and the tank shell. As the foam settles, water drains out under
the foam dams and should be removed through the tank roof drain system to avoid overweighing and sinking the roof.
Depending on government regulations and company policy, storage tanks may be provided with fixed or semi-fixed foam systems which include: piping to the tanks, foam risers and foam chambers on the tanks; subsurface injection piping and nozzles inside the bottom of tanks; and distribution piping and foam dams on the tops of tanks.With fixed systems, foam-water solutions are generated in centrally located foam houses and pumped to the tank through a piping system. Semi-fixed foam systems typically use portable foam tanks, foam generators and pumps which are brought to the tank involved, connected to a water supply and connected to the tank’s foam piping.
Water-foam solutions may also be centrally generated and distributed within the facility through a system of piping and hydrants, and hoses would be used to connect the nearest hydrant to the tank’s semi-fixed foam system. Where tanks are not provided with fixed or semi-fixed foam systems, foam may be applied onto the tops of tanks, using foam monitors, fire hoses and nozzles. Regardless of the method of application, in order to control a fully involved tank fire, a specific amount of foam must be applied using special techniques at a specific concentration and rate of flow for a minimum amount of time depending primarily on the size of the tank, the product involved and the surface area of the fire. If there is not enough foam concentrate available to meet the required application criteria, the possibility of control or extinguishment is minimal.
Only trained and knowledgeable fire-fighters should be allowed to use water to fight liquid petroleum tank fires. Instantaneous eruptions, or boil-overs, can occur when water turns into steam upon direct application onto tank fires involving crude or heavy petroleum products. As water is heavier than most hydrocarbon fuels, it will sink to the bottom of a tank and, if enough is applied, fill the tank and push the burning product up and over the top of the tank.
Water is typically used to control or extinguish spill fires around the outside of tanks so that valves can be operated to control product flow, to cool the sides of involved tanks to prevent boiling liquid-expanding vapour explosions (BLEVEs-see the section “Fire hazards of LHGs” below) and to reduce the effect of heat and flame impingement on adjacent tanks and equipment. Because of the need for specialized training, materials and equipment, rather than allow employees to attempt to extinguish tank fires, many terminals and bulk plants have established a policy to remove as much product as possible from the involved tank, protect adjacent structures from heat and flame and allow the remaining product in the tank to burn under controlled conditions until the fire burns out.
Terminal and bulk plant health and safety
Storage tank foundations, supports and piping should be regularly inspected for corrosion, erosion, settling or other visible damage to prevent loss or degradation of product. Tank pressure/vacuum valves, seals and shields, vents, foam chambers, roof drains, water draw-off valves and overfill detection devices should be inspected, tested and maintained on a regular schedule, including removal of ice in the winter. Where flame arrestors are installed on tank vents or in vapour recovery lines, they have to be inspected and cleaned regularly and kept free of frost in the winter to ensure proper operation. Valves on tank outlets which close automatically in case of fire or drop in pressure should be checked for operability.
Dyke surfaces should drain or slope away from tanks, pumps and piping to remove any spilled or released product to a safe area. Dyke walls should be maintained in good condition, with drain valves kept closed except when draining water and dyke areas excavated as needed to maintain design capacity. Stairways, ramps, ladders, platforms and railings to loading racks, dykes and tanks should be maintained in a safe condition, free of ice, snow and oil. Leaking tanks and piping should
be repaired as soon as possible. The use of victaulic or similar couplings on piping within dyked areas which could be exposed to heat should be discouraged to prevent lines from opening during fires.
Safety procedures and safe work practices should be established and implemented, and training or education provided, so that terminal and bulk plant operators, maintenance personnel, tank truck drivers and contractor personnel can work safely. These should include, as a minimum, information concerning the basics of hydrocarbon fire ignition, control and extinguishment; hazards and protection from exposures to toxic substances such as hydrogen sulphide and polynuclear aromatics in crude oil and residual fuels, benzene in gasoline and additives such as tetraethyl lead and methyl-tert-butyl ether (MTBE); emergency response actions; and normal physical and climatic hazards associated with this activity.
Asbestos or other insulation may be present in the facility as protection for tanks and piping. Appropriate safe-work and personal protective measures should be established and followed for handling, removing and disposing of such materials.
Environmental protection
Terminal operators and employees should be aware of and comply with government regulations and company policies covering environmental protection of ground and surface water, soil and air from pollution by petroleum liquids and vapours, and for handling and removing hazardous waste.
· Water contamination. Many terminals have oil/water separators to handle contaminated water from tank containment areas, run-off from loading racks and parking areas and water drained from tanks and open-top tank roofs. Terminals may be required to meet established water quality standards and obtain permits before discharging water.
· Air pollution. Air pollution prevention includes minimizing releases of vapours from valves and vents. Vapour recovery units collect vapours from loading racks and marine docks, even when tanks are vented prior to entry. These vapours are either processed and returned to storage as liquids or burned.
· Spills on land and water. Government agencies and companies may require that oil storage facilities have spill prevention control and counter-measure plans, and that personnel be trained and aware of the potential hazards, notifications to be made and the actions to take in case of a spill or release. In addition to handling spills within the terminal facility, personnel are often trained and equipped to respond to offsite emergencies, such as a tank truck rollover.
· Sewage and hazardous waste. Terminals may be required to meet regulatory requirements and obtain permits for discharge of sewage and oily waste to public or privately owned treatment works. Various government requirements and company procedures may apply to the onsite storage and handling of hazardous waste such as asbestos insulation, tank cleaning residue and contaminated product. Workers should be trained in this activity and be made aware of the potential hazards from exposures which could occur.
LHG Storage and Handling
Bulk storage tanks
LHGs are stored in large bulk storage tanks at the point of process (gas and oil fields, gas plants and refineries) and at the point of distribution to the consumer (terminals and bulk plants). The two most commonly used methods of bulk storage of LHGs are:
· Under high pressure at ambient temperature. LHG is stored in steel pressure tanks (at 1.6 to 1.8 mPa) or in underground impermeable rock or salt formations.
· Under pressure close to atmospheric at low temperature. LHG is stored in thin-walled, heatinsulated steel storage tanks; in reinforced concrete tanks above and below ground; and in underground cryogenic storage tanks. Pressure is maintained close to atmospheric (0.005 to 0.007 mPa) at a temperature of -160°C for LNG stored in cryogenic underground storage tanks.
LPG bulk storage vessels are either cylindrically (bullet) shaped horizontal tanks (40 to 200 ) or spheres (up to 8,000 ). Refrigerated storage is typical for storage in excess of 2,400 . Both horizontal tanks, which are fabricated in shops and transported to the storage site, and spheres, which are built onsite, are designed and constructed in accordance with rigid specifications, codes and standards.
The design pressure of storage tanks should not be less than the vapour pressure of the LHG to be stored at the maximum service temperature. Tanks for propane-butane mixtures should be designed for 100% propane pressure. Consideration should be given to additional pressure requirements resulting from the hydrostatic head of the product at maximum fill and the partial pressure of non-condensible gases in the vapour space. Ideally, liquefied hydrocarbon gas storage vessels should be designed for full vacuum. If not, vacuum relief valves must be provided. Design features should also include pressure relief devices, liquid level gauges, pressure and temperature gauges, internal shut-off valves, back flow preventers and excess flow check valves. Emergency fail-safe shut-down valves and high level signals may also be provided.
Horizontal tanks are either installed aboveground, placed on mounds or buried underground, typically downwind from any existing or potential sources of ignition. If the end of a horizontal tank ruptures from over-pressurization, the shell will be propelled in the direction of the other end. Therefore, it is prudent to place an aboveground tank so that its length is parallel to any important structure (and so that neither end points toward any important structure or equipment). Other factors include tank spacing, location, and fire prevention and protection. Codes and regulations specify minimum horizontal distances between pressurized liquefied hydrocarbon gas storage vessels and adjoining properties, tanks and important structures as well as potential sources of ignition, including processes, flares, heaters, power transmission lines and transformers, loading and unloading facilities, internal combustion engines and gas turbines.
Drainage and spill containment are important considerations in designing and maintaining liquid hydrocarbon gas tank storage areas in order to direct spills to a location where they will minimize risk to the facility and surrounding areas. Dyking and impounding may be used where spills present a potential hazard to other facilities or to the public. Storage tanks are not usually dyked, but the ground is graded so that vapours and liquids do not collect underneath or around the storage tanks, in order to keep burning spills from impinging upon storage tanks.
Cylinders
LHGs for use by consumers, either LNG or LPG, are stored in cylinders at temperatures above their boiling points at normal temperature and pressure. All LNG and LPG cylinders are provided with protective collars, safety valves and valve caps. The basic types of consumer cylinders in use are:
· vapour withdrawal (1/2 to 50 kg) cylinders used by consumers, with larger ones usually refillable on an exchange basis with the supplier
· liquid withdrawal cylinders for dispensing into small consumer-owned refillable cylinders
· motor vehicle fuel cylinders, including vehicle cylinders (40 kg) permanently installed as fuel tanks on motor vehicles and filled and used in the horizontal position, and industrial truck cylinders designed to be stored, filled and handled in the upright position, but used in the horizontal position.
Properties of hydrocarbon gases
According to the NFPA, flammable (combustible) gases are those which burn in the normal concentrations of oxygen in air. The burning of flammable gases is similar to flammable hydrocarbon liquid vapours, as a specific ignition temperature is needed to initiate the burning reaction, and each will burn only within a certain defined range of gas-air mixtures. Flammable liquids have a flashpoint, which is the temperature (always below the boiling point) at which they emit sufficient vapours for combustion. There is no apparent flashpoint for flammable gases, since they are normally at temperatures above their boiling points, even when liquefied, and are therefore always at temperatures well in excess of their flashpoints.
The NFPA (1976) defines compressed and liquefied gases as follows:
· “Compressed gases are those which at all normal atmospheric temperatures inside their containers, exist solely in the gaseous state under pressure.”
· “Liquefied gases are those which at normal atmospheric temperatures inside their containers, exist partly in the liquid state and partly in the gaseous state, and are under pressure as long as any liquid remains in the container.”
The major factor which determines the pressure inside the vessel is the temperature of the liquid stored. When exposed to the atmosphere, the liquefied gas very rapidly vaporizes, travelling along the ground or water surface unless dispersed into the air by wind or mechanical air movement. At normal atmospheric temperatures, about one-third of the liquid in the container will vaporize.
Flammable gases are further classified as fuel gas and industrial gas. Fuel gases, including natural gas (methane) and LPGs (propane and butane), are burned with air to produce heat in ovens, furnaces, water heaters and boilers. Flammable industrial gases, such as acetylene, are used in processing, welding, cutting and heat-treating operations. The differences in combustion properties of LNG and LPGs are shown in table 102.11.
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Table 102.11 Typical approximate combustion properties of liquified hydrocarbon gases
Type gas Flammable range
(% gas in air) Vapour pressure
(psig at 21 °C) Normal init. boiling
point (°C) Weight (pounds/gal) BTU per Specific gravity
(Air = 1)
LNG 4.5-14 1.47 -162 3.5-4 1,050 9.2-10
LPG (propane) 2.1-9.6 132 -46 4.24 2,500 1.52
LPG (butane) 1.9-8.5 17 -9 4.81 3,200 2.0
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Safety hazards of LPG and LNG
The safety hazards applicable to all LHGs are associated with flammability, chemical reactivity, temperature and pressure. The most serious hazard with LHGs is the unplanned release from containers (canisters or tanks) and contact with an ignition source. Release can occur by failure of the container or valves for a variety of reasons, such as overfilling a container or from overpressure venting when the gas expands due to heating.
The liquid phase of LPG has a high coefficient of expansion, with liquid propane expanding 16 times and liquid butane 11 times as much as water with the same rise in temperature. This property must be considered when filling containers, as free space must be left for the vapour phase. The correct quantity to be filled is determined by a number of variables, including the nature of the liquefied gas, temperature at time of filling and expected ambient temperatures, size, type (insulated or uninsulated) and location of container (above or below ground). Codes and regulations establish allowable quantities, known as “filling densities”, which are specific for individual gases or families of similar gases. Filling densities may be expressed by weight, which are absolute values, or by liquid volume, which must always be temperature corrected.
The maximum amount that LPG pressure containers should be filled with liquid is 85% at 40 °C (less at higher temperatures). Because LNG is stored under low temperatures, LNG containers may be liquid filled from 90% to 95%. All containers are provided with overpressure relief devices which normally discharge at pressures relating to liquid temperatures above normal atmospheric temperatures. As these valves cannot reduce the internal pressure to atmospheric, the liquid will always be at a temperature above its normal boiling point. Pure compressed and liquefied hydrocarbon gases are non-corrosive to steel and most copper alloys. However, corrosion can be a serious problem when sulphur compounds and impurities are present in the gas.
LPGs are 1-1/2 to 2 times heavier than air and, when released in air, tend to quickly disperse along the ground or water surface and collect in low areas. However, as soon as the vapour is diluted by air and forms a flammable mixture, its density is essentially the same as air, and it disperses
differently. Wind will significantly reduce the dispersion distance for any size of leak. LNG vapours react differently from LPG. Because natural gas has a low vapour density (0.6), it will mix and disperse rapidly in open air, reducing the chance of forming a flammable mixture with air. Natural gas will collect in enclosed spaces and form vapour clouds which could be ignited. Figure 102.17 indicates how a liquefied natural gas vapour cloud spreads downwind in different spill situations.
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Figure 102.17 Extension of LNG vapour cloud downwind from different spills (wind speed 8.05 km/h)
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Although LHG is colourless, when released in air its vapours will be noticeable due to the condensation and freezing of water vapour contained in the atmosphere which is contacted by the vapour. This may not occur if the vapour is near ambient temperature and its pressure is relatively low. Instruments are available which can detect the presence of leaking LHG and signal an alarm at levels as low as 15 to 20% of the lower flammable limit (LFL). These devices may also stop all operations and activate suppression systems, should the concentrations of gas reach 40 to 50% of the LFL. Some industrial operations provide forced ventilation to keep leaking fuel-air concentrations below the lower flammable limit. Heater and furnace burners may also have devices which automatically stop the flow of gas if the flame is extinguished.
LHG leakage from tanks and containers may be minimized by the use of limiting and flow control devices. When decompressed and released, LHG will flow out of containers with a low negative pressure and low temperature. The auto refrigeration temperature of the product at the lower pressure must be considered when selecting materials of construction for containers and valves, to prevent metal embrittlement followed by rupture or failure due to exposure to low temperatures.
LHG can contain water in both its liquid and gaseous phases. Water vapour can saturate gas in a specific amount at a given temperature and pressure. If the temperature or pressure changes, or the water vapour content exceeds the evaporation limits, the water condenses. This can create ice plugs in valves and regulators and form hydrocarbon hydrate crystals in pipelines, devices and other apparatus. These hydrates can be decomposed by heating the gas, lowering the gas pressure or introducing materials, such as methanol, which reduce the water vapour pressure.
There are differences in the characteristics of compressed and liquefied gases which must be considered from safety, health and fire aspects. As an example, the differences in the characteristics of compressed natural gas and LNG are illustrated in table 102.12.
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Table 102.12
Comparison of characteristics of compressed and liquified gas
Type gas Flammable range
(% gas in air) Heat release rate (BTU/gal) Storage condition Fire risks Health risks
Compressed natural gas 5.0-15 19,760 Gas at 2,400 to 4,000 psi Flammable gas Asphyxiant; overpressure
LNG 4.5-14 82,450 Liquid at 40-140 psi Flammable gas 625:1 expansion ratio; BLEVE Asphyxiant; cryogenic liquid
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Health hazards of LHGs
The primary occupational injury concern in handling LHGs is the potential hazard of frostbite to the skin and eyes from contact with liquid during handling and storage activities including sampling, measuring, filling, receiving and delivery. As with other fuel gases, when improperly burned, compressed and liquefied hydrocarbon gases will emit undesirable levels of carbon monoxide.
Under atmospheric pressures and low concentrations, compressed and liquefied hydrocarbon gases are normally non-toxic, but they are asphyxiants-they will displace oxygen (air) if released in enclosed or confined spaces. Compressed and liquefied hydrocarbon gases may be toxic if they contain sulphur compounds, especially hydrogen sulphide. Because LHGs are colourless and odourless, safeguards include adding odourants, such as mercaptans, to consumer fuel gases to aid in leak detection. Safe work practices should be implemented to protect workers from exposure to mercaptans and other additives during storage and injection. Exposure to LPG vapours in concentrations at or above the LFL may cause a general central nervous system depression similar to anaesthesia gases or intoxicants.
Fire hazards of LHGs
Failure of liquefied gas (LNG and LPG) containers constitutes a more severe hazard than failure of compressed gas containers, as they release greater quantities of gas. When heated, liquefied gases react differently from compressed gases, because they are two-phase (liquid-vapour) products. As the temperature rises, the vapour pressure of the liquid is increased, resulting in increased pressure inside the container. The vapour phase first expands, followed by expansion of the liquid, which then compresses the vapour. The design pressure for LHG vessels is therefore assumed to be near that of the gas pressure at maximum possible ambient temperature.
When a liquefied gas container is exposed to fire, a serious condition can occur if the metal in the vapour space is allowed to heat. Unlike the liquid phase, the vapour phase absorbs little heat. This allows the metal to heat rapidly until a critical point is reached at which an instantaneous, catastrophic explosive failure of the container occurs. This phenomenon is known as a BLEVE. The magnitude of a BLEVE depends on the amount of liquid vaporizing when the container fails, the size of the pieces of exploded container, the distance they travel and the areas they impact. Uninsulated LPG containers may be protected against a BLEVE by applying cooling water to those areas of the container which are in the vapour phase (not in contact with LPG).
Other more common fire hazards associated with compressed and liquefied hydrocarbon gases include electrostatic discharge, combustion explosions, large open-air explosions and small leaks from pump seals, containers, valves, pipes, hoses and connections.
· Electrostatic charges may be generated when LHG is shipped in pipelines, when loaded and unloaded, in blending and filtering and during tank cleaning.
· Combustion explosions result when escaping gas or vapour is contained in a confined space or structure and combines with air to create a flammable mixture. When this flammable mixture contacts a source of ignition, it burns instantaneously and rapidly, producing extreme heat. The very hot air expands quickly, causing a considerable rise in pressure. If the space or structure is not strong enough to contain this pressure, a combustion explosion occurs.
· Flammable gas fires result when there is no confinement of the escaping gas or vapours, or ignition occurs when only a small amount of gas has been released.
· Large open-air explosions occur when a massive failure of a container releases a large vapour cloud of gas which is ignited before it disperses.
Controlling sources of ignition in hazardous areas is essential for the safe handling of compressed and liquefied hydrocarbon gases. This may be accomplished by establishing a permit system to authorize and control hot work, smoking, operation of motor vehicles or other internal combustion engines, and the use of open flames in areas where compressed and liquefied hydrocarbon gas is transported, stored and handled. Other safeguards include the use of properly classified electrical equipment and bonding and grounding systems to neutralize and dissipate static electricity.
The best means of reducing the fire hazard of leaking compressed or liquefied hydrocarbon gas is to stop the release, or shut off the flow of product, if possible. Although most LHGs will vaporize upon contact with air, lower vapour pressure LPGs, such as butane, and even some higher vapour pressure LPGs, such as propane, will pool if ambient temperatures are low. Water should not be applied to these pools, as it will create turbulence and increase the rate of vaporization. Vaporization from pool spills can be controlled by the careful application of foam. Water, if correctly applied against a leaking valve or small rupture, can freeze upon contact with the cold LHG and block the leak. LHG fires require controlling heat impingement upon storage tanks and containers by the application of cooling water. While compressed and liquefied hydrocarbon gas fires can be extinguished by the use of water spray and dry powder extinguishers, it is often more prudent to allow controlled burning so that a combustible explosive vapour cloud does not form and re-ignite should the gas continue to escape after the fire is extinguished.
