In the post-World war II period, the steels used in the oil and gas industry were quite different from what we use today. This tip of the month (TOTM) presents a brief overview of improvements in the steels used in oil and gas processing equipment for safer and more reliable operations.
Plate was SA-285C a 55,000 psi (379 MPa) tensile steel that was relatively soft and easy to fabricate. It was not killed steel and therefore, not fine grain steel. The low tensile strength meant thicker vessels and because of poor welding techniques, spot or no radiography at all was common, making the items even thicker. Figure 1 shows a vacuum tower made of SA-285C from the 1950’s. This tower was constructed in 1961 by Chicago Bridge and Iron for the Shell Martinez Refinery in California.
Figure 1. A vacuum tower made of SA-285C from the 1950’s. Shell Martinez serial #C-4201
A plate designated SA-212B Firebox was in use for higher tensile applications. It had a 70,000 psi (482 MPa) tensile, but was coarse grained and had the undesirable characteristic of fracturing in the parent metal after thermal expansion and contraction over a period of time. Due to repeated failures in service, this material was removed from the ASME Boiler and Pressure Vessel Code Section II in 1968 as being unfit for thermal cycling. Figure 2 presents a high pressure molecular sieve tower which was fractured by thermal cycling.
Figure 2. An example of fracturing in a vessel made from the SA-212B Firebox steel.
Pipe used in the 1950’s was SA-53B, which could be Electric Resistance Welded or seamless. It was not killed steel. It had a 60,000 psi (413 MPa) tensile and was the pipe of choice for vessel, tank, and piping fabrication at the time.
The forging of the 1950’s was SA-181, a 60,000 psi (413 MPa) tensile steel used for flanges, forged steel fittings, and heavy nozzles. It was not killed steel.
Since none of these steels were killed, fine grained steels, their use declined rapidly as the industry moved into harsh environments such as the North Slope of Alaska and the processing of acid gases and sour crudes.
Killed steel came into wide use during the 1960’s. Killed steel is produced in the ladle by adding silicon or aluminum to prevent further deoxidation of the heat. Molten steel contains dissolved oxygen which can cause bubbles in the cooling and solidification process. The addition of silicon or aluminum stops the reaction of the oxygen with carbon, producing a fine grain steel free from dissolved gases, highly homogenous with excellent fabrication properties.
During the 1960’s, the SA-516 family of plate steels was introduced. These steels were silicon killed, fine grained, and produced excellent properties. The fine grain gave the steel impact resistance at temperatures down to -50 °F (-45.5 °C). The SA-516 suffix defines the tensile strength, 55,000, 60,000, 65,000, and 70,000 psi (379, 413, 448, and 482 MPa).
SA-516-55 was designed to replace SA-285C
SA-516-60 was designed for use in very cold service.
SA-516-65 was for intermediate tensile requirements
SA-516-70 was to replace SA-212B Firebox plate
The chemical and mechanical properties of these four grades of steel overlap to the extent that one plate can actually meet all four specifications.
Approximately 90% of all custom carbon steel pressure vessels manufactured for the oil and gas industry in the world today are made from SA-516-70 or its UNS (Unified Numbering System) equivalent. Figure 3 presents an example of a vertical drum made of SA-516-70.
Figure 3. An example of a vertical drum made of SA-516-70
During the 1960’s SA-106 pipe replaced SA-53 as the pipe of choice. Unlike SA-53B, SA-106B is seamless, killed, fine grain steel. It has a 60,000 psi (413 MPa) psi tensile.
In 1978, SA-105 forgings replaced the SA-181 as the forging material of choice. SA-105 has a tensile of 70,000 psi (482 MPa), so the pressure ratings of B16.5 carbon steel flanges increased.
Around the year 2000, the pipe manufactures improved their processes making SA-106 pipe to the point that they are able to meet the chemical and mechanical properties of SA-106B and SA-106C in the same heat.
Since 2003, basically all SA-106 pipe is dual certified to SA-106B and SA-106C. This means that all three major components of a pressure vessel or shell and tube heat exchanger now have the same tensile strength, 70,000 psi (482 MPa). Figure 4 presents pipes made of SA-106.
Figure 4. Pipes made of SA-106
Austenitic Stainless steels (300 series) fifty years ago were made to straight grade (0.08 carbon) or “L” grade (0.03 carbon). Steel service centers had to maintain stocks of both grades. About 45 years ago, the stainless mills improved their manufacturing techniques to produce dual certified stainless steel, meaning that virtually all stainless in the steel service centers meets the criteria of 0.03 carbon for “L” grade but also meets the mechanical properties of straight grade. Straight grades have a higher tensile allowing for the use of a thinner plate than “L” grade plate.
Figure 5 presents an example of a separator made of stainless vessel. This 316 stainless separator is the first to be used offshore in place of a clad vessel. Since the temperature was low, the higher tensile allowed this item to be thinner, saving weight, and not require PWHT (Post Weld Heat Treatment), impact testing or special paint.
Figure 5. This 316 stainless separator is the first to be used offshore in place of a clad vessel
Summary:
In the last half century, the adoption of new technology in the manufacturing of fine grain steel plates, pipes and forgings has vastly improved the quality of the steels used in Oil and Gas Processing Equipment. Along with improvements in the welding processes used to construct Oil and Gas Processing Equipment, vessels, exchangers, piping and storage tanks are safer than ever before.
In the November 2011 tip of the month (TOTM) we presented the compressor calculations of a case study. We compared the rigorous method results with the values from the shortcut methods. The rigorous method was based on an equation of state like the Soave-Redlich-Kwong (SRK) for calculating the required enthalpies and entropies. The enthalpies and entropies are used to determine the power requirement and the discharge temperatures. The results indicated that the accuracy of the shortcut method is sensitive to the value of ideal gas state heat capacity ratio, k.
From a calculation viewpoint alone, the power calculation is particularly sensitive to the specification of mass flow rate, suction temperature and pressure, and discharge temperature and pressure. A compressor is going to operate under varying values of the variables affecting its performance. Thus the most difficult part of a compressor calculation is specification of a reasonable range for each variable and not the calculation itself. Reference [1] emphasizes that using a single value for each variable is not the correct way to evaluate a compression system.
Normally, the thermodynamic calculations are performed for an ideal (reversible) process. The results of a reversible process are then adapted to the real world through the use of a thermodynamic efficiency. In the compression process there are three ideal processes that can be visualized: 1) an isothermal process (PV1=C1), 2) an isentropic process (PVk=C2) and 3) a polytropic process (PVn=C3). Any one of these processes can be used suitably as a basis for evaluating compression power requirements by either hand or computer calculation. The isothermal process, however, is seldom used as a basis because the normal industrial compression process is not even approximately carried out at constant temperature.
Note that Dresser Rand is doing quite a lot of work with “Near constant temperature” compression especially for CO2 compression from vent stacks. For detail refere to:
In this TOTM, we will demonstrate how to determine the efficiency of a compressor from measured flow rate, composition, suction and discharge temperatures and pressures. A rigorous calculation based on an equation of state and a shortcut method are considered and the results are compared.
Compress Efficiency
Compressor efficiencies vary with compressor type, size, and throughput. They can only be determined (afterward) by a compressor test, although compressor manufacturers can usually provide good estimates. For planning purposes, reference [2] suggests the following values for the overall efficiencies:
Table 1. Overall Compressor Efficiencies [2]
Compressor Type
Efficiency, η
Centrifugal
0.70 – 0.85
High Speed Reciprocating
0.72 – 0.85
Low Speed Reciprocating
0.75 – 0.90
Rotary Screw
0.65 – 0.75
Reference [2] indicates that these overall efficiencies include gas friction within the compressor, the mechanical losses (bearings, seals, gear-box, etc.), and gear-box losses. The mechanical efficiency varies with compressor size and type, but 95% is a useful planning number. When calculating the compressor head and discharge temperature the efficiency used will be isentropic or polytropic (isentropic efficiency is sometimes called adiabatic efficiency). Adding 3-4 % efficiency (mechanical losses) to the overall efficiencies in Table 1 will generally give a good estimate of the thermodynamic efficiency [2].
To evaluate the performance of an existing compressor, the objective is to calculate the compressor efficiency (η) and power requirement.
Known and measured properties are:
a. Standard condition gas volume flow rate (qS) or gas mass rate ()
b. Gas composition (zi)
c. Suction pressure (P1) and temperature (T1)
d. Discharge pressure (P2) and temperature (T2)
Estimating Efficiency – Rigorous Method
The heart of any commercial process flow simulation software is an equation of state. Due to their simplicity and relative accuracy, a cubic EOS such as Soave Redlich-Kwong (SRK) [3] or Peng-Robinson [4] is used. These equations are used to calculate Vapor-Liquid-Equilibria (VLE), enthalpy (h), and entropy (s). With proper binary interaction coefficients, the process simulation results of these two equations are practically the same. Therefore, only the SRK is used in this work.
The isentropic efficiency is defined by
Where:
ηIsen = Isentropic efficiency
h1 = Suction enthalpy calculated at P1, T1, and composition (zi)
h2 = Discharge enthalpy calculated at P2, T2, and composition (zi)
h2Isen = Isentropic discharge enthalpy at P2(or T2), S2Isen =S1, and composition (zi)
= Mass flow rate
The computation compressor efficiency or power involves two steps
1. Determination of the ideal or isentropic (reversible and adiabatic) enthalpy change (h2Isen-h1) of the compression process.
2. Determination of the actual enthalpy change (h2-h1).
The step-by-step calculation based on an EOS:
a. Assume steady state, i.e.
b. Assume the feed composition remain unchanged
c. Calculate suction enthalpy h1=f(P1, T1, and zi) and entropy s1=f(P1, T1, and zi) by EOS
d. Assume isentropic process and set s2Isen = f (P2, T2Isen, zi) = s1 = f (P1, T1, zi).
e. Calculate the ideal enthalpy (h2Isen) at discharge condition for known zi, T2 (or P2) and s2Isen.
f. Calculate the actual enthalpy (h2) at discharge condition for known zi, T2 and P2.
g. Calculate isentropic efficiency by Equation 1: µIsen = (h2Isen – h1)/(h2 – h1)
h. Calculate power by Equation 2:
Estimating Efficiency – Shortcut Method
The isentropic path exponent (k) or ideal gas heat capacity ratio (k=CP/CV) can be calculated by the correlation presented in the May 2013 TOTM:
Where:
T= Temperature, K (°R)
= Gas relative density; ratio of gas molecular weight to air molecular weight
A= 0.000272 (0.000151)
The actual discharge temperature based on an isentropic path can be estimated by
Solving for the isentropic efficiency,
Similarly, the actual discharge temperature based on a polytropic path can be estimated by
Solving the above equation for the polytropic path coefficient (n):
Similarly, the actual discharge temperature based on a polytropic path can be estimated (ηPoly) by:
The isentropic head is calculated by
Similarly, the polytropic head is calculated by
For an isentropic (reversible and adiabatic) process the power is calculated by
Or for a polytropic process the power is calculated by
Alternatively:
Where:
Head= Compressor head, m (ft)
Power= Compressor power, kW (HP)
R= Universal gas constant, 848 kg-m/(kmol-K) or (1545 ft-lbf/(lbmol-°R))
PS= Standard condition pressure, kPa (psia)
P1= Suction pressure, kPa (psia)
P2= Discharge pressure, kPa (psia)
TS= Standard condition temperature, K (°R)
T1= Suction temperature, K (°R)
T2= Discharge temperature, K (°R)
qS= Gas volumetric rate at the standard condition, Sm3/d (scf/day)
Za= Average gas compressibility factor = (Z1+Z2)/2
Z1= Gas compressibility factor at the suction condition
Z2= Gas compressibility factor at the discharge condition
MW= Gas molecular weight
The power calculation should be made per stage of compression and then summed for all stages connected to a single driver.
The step-by-step calculation for shortcut method
a. Calculate the isentropic exponent (k) by Equation 3 using the average temperature defined by T = (T1+3T2)/4. This form of average temperature was defined to obtain better match between the rigorous and shortcut method results.
b. Calculate the isentropic efficiency (ηIsen) by Equation 5.
c. Calculate the polytropic coefficient (n) by Equation 7.
d. Calculate the polytropic efficiency (ηPoly) by Equation 8.
e. Calculate the isentropic and polytropic heads by Equations 9 and 10, respectively.
f. Calculate the required power per stage by either Equation 11 or 12.
Case Study
A natural gas mixture is compressed using a three-stage centrifugal compressor. The process flow diagram is shown in Figure 1. For each stage, the measured pressure, and temperature are presented in Table 1. The measured feed composition, flowrates, and calculated molecular weight and relative density are presented in Table 2.
Figure 1. Process flow diagram for a 3-stage compression
Table 1. Measured temperature and pressure for the three stages of compression
Table 2. Gas analysis and flow rate for the three stages of compression
* Calculated
Results and Discussions
The process flow diagram shown in Figure 1 was simulated by ProMax software [5] to perform the rigorous calculations using the SRK EOS. The program calculated polytropic and isentropic efficiencies, heads, and compression power. The program also calculated the isentropic path exponent (k), and polytropic path exponent (n). These calculated results are presented in Table 2 for all three stages under SRK headingings. The calculations performed by ProMax are very similar to the step-by-step of a through h described in the rigorous section. Table 2 also presents the shortcut caculation results for the corresponding values under the shortcut heading. The shortcut calculations are based on the step-by-step of a through f described in the shortcut method section. The error percent between the rigrous method and the shortcut methods for each stage are presented in Table 2, too. Table 2 indicates that excellent agreements are obtained for stages 1 and 2. However, larger deviations are obseved for the isetropic and polytropic exponents of stage 3 due to high pressure operation which deviated too far from ideal gas state conditions.
Table 3. Summary of the rigorous and shortcut calculated results
Conclusions
Table 2 indicates that there are good agreements between the shortcut and the rigorous results. The differences between the rigorous and shortcut method results for facilities calculations and planning purposes are negligible. For stage 3, due to high-pressure operation and deviating too far from the ideal gas state condition, a larger error is observed for the isentropic exponent (k).
The calculated isentropic exponent (k) in the ProMax [5] is not the ideal gas state heat capacity (CP/CV) ratio. It is the value of the isentropic exponent that is required to yield an isentropic path from inlet to outlet. Its value is calculated as an integration of that path. Thus it is somewhat of an “average” value representing the true isentropic path. For ideal gases, the value would be equal (CP/CV) ratio.
This error in ‘k’ also illustrates the importance of specifying which correlation is to be used when ordering a performance test (ie, refer to ASME PTC-10 for additional details), so that client and vendor are on the same agreement moving forwards with regard to molecular weight (MW) and k for the test fluid. For further detail refer to reference [6] and August and September 2010 TOTMs [7, 8].
It may also be worth noting that when trending ‘n’ and the polytropic efficiency to evaluate machine condition, the relative accuracy of measurement instrument/equipment (temperature and pressure transducers) and mapping of compressor performance to the original performance curve (actual gas volume flow rate vs speed), introduces many potential erroneous sources into this daily evaluation.
Note that the accuracy of the shortcut methods is dependent on the values of k and n. The definition of average temperature in the shortcut method was adjusted to obtain a better match between the isentropic path exponent (k) calculated by rigorous method.
1. Maddox, R. N. and L. L. Lilly, “Gas conditioning and processing, Volume 3: Advanced Techniques and Applications,” John M. Campbell and Company, 2nd Ed., Norman, Oklahoma, USA, 1990.
2. Campbell, J.M., Gas Conditioning and Processing, Volume 2: The Equipment Modules, 9th Edition, 2nd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, 2014.
For transportation of crude oil, the pumping power requirement varies as the crude oil viscosity changes. Increasing °API or line average temperature reduces the crude oil viscosity. The reduction of viscosity results in higher Reynolds number, lower friction factor and in effect, lower pumping power requirements.
In the March 2009 tip of the month (TOTM), procedures for calculation of friction losses in oil and gas pipelines were presented. The sensitivity of friction pressure drop with the wall roughness factor was also demonstrated. In the August 2009 TOTM, we also demonstrated the effect crude oil °API and the pipeline average temperature on the pumping requirement.
In practical situations, an originating station takes crude out of storage and the midline stations taking suction from the upstream section of pipeline. Oil in the tank is often at ambient temperature, whereas once in the pipeline, the oil cools (or warms) to the same temperature as the ground. In some parts of the world, the tank might be at +38 °C (+100 °F). The first midline pumping station could operate at 18 °C (65 °F), and all subsequent pumping stations might operate at ground temperature, or notionally 9 °C (48 °F) with some seasonal variation. Therefore, a sound pipeline design should consider expected variation in crude oil viscosity which is normally a function of crude oil °API, and the line average temperature. In addition to °API and temperature, chemical additives may also affect crude oil pipeline pressure drop.
To reduce pressure drop and increase pipeline capacity, oil industry has utilized drag reducing agents. Drag-reducing agents, or drag-reducing polymers, are additives in pipelines that reduce turbulence in a pipe. Usually used in petroleumpipelines, they increase the pipeline capacity by reducing turbulence and therefore allowing the oil to flow more efficiently [1]. In addition to drag reducing agents, another group of chemicals called “Incorporative Additives”, which reduces crude oil viscosity, may be used. Halloran presented a series of general reading articles on chemical additives [2-4].
In this TOTM, we will demonstrate the effect of an incorporative additive on crude oil viscosity and consequently on pressure drop for crude oil pipeline transportation.
Case Study: Part 1 – Viscosity Reduction
The laboratory measured kinematic viscosity for different °API crude oil samples without and with “Incorporative Additive” at 50 °C (122 °F) reported by Oil Flux Americas [6] are shown in Table 1. The calculated density, absolute viscosity and percent reduction in viscosity for each oil sample at 50 °C (122 °F) are also shown in this table. As noted in this table, the lower °API (heavier oil), the greater the reduction in oil viscosity. The measured kinematic viscosities as a function of crude oil °API are shown in Figure 1. The absolute viscosity is calculated by multiplying the measured kinematic viscosity by density. The corresponding calculated absolute viscosities are also shown in Table 1 for crude oil samples “Without” and “With” additive, respectively.
Table 1. Measured kinematic viscosity [6] and absolute viscosity for several crude oil samples at 50 °C (122 °F) without and with chemical additive.
cSt = (mm)2/s cP = Poise/100 = Pa.s/1000 =kg/m-s/1000 = 0.000672 lbm/ft-sec * Used in the case studiesFigure 1. Effect of chemical additive on crude oil absolute viscosity at 50°C (122 °F)
The absolute viscosities (μ) at 50 °C (122 °F) are fitted to a quadratic equation as follows:
The absolute viscosities and the fitted correlations are shown in Figures 2 and 3 for crude oil samples “without” and “with” chemical additive, respectively.
Case Study: Part 2 – Pressure Drop Calculations
For a case study, we will consider a 55 km (34.18 miles) pipeline with an outside diameter of 406.4 mm (16 in) carrying crude oil with two separate flow rates of 7,950 and 15,900 m3/d (50,000 and 100,000 bbl/day). The wall thickness was estimated to be 5.7 mm (0.225 in). The wall roughness is 46 microns (0.0018 in) or a relative roughness (ε/D) of 0.0001. The procedures outlined in the March 2009 TOTM were used to calculate the line pressure drop due to friction. Since the objective is to study the effect of incorporative chemical additive, we will ignore elevation change.
It is also assumed the line temperature is constant at 50 °C (122 °F). The change in pressure drop (ΔP) due to changes in crude oil viscosity for this case study will be calculated and presented in the following sections.
Figure 2. Measured absolute viscosity at 50°C (122 °F) for crude oils without chemicalFigure 3. Measured absolute viscosity at 50°C (122 °F) for crude oils with chemical
Tables 2a and 2b show the calculated pressure drop for four different crude oils with varying viscosities in System International (SI) and field units (FPS – Foot, Pound and Second), respectively. The measured absolute viscosities were used to calculate pressure drops for all cases. The oil flow rate is 7,950 m3/d (50,000 bbl/day). Table 2 indicates that by using incorporative additives a reduction of up to 24% in pressure drop is achieved for this case study. The results in this table also indicate that the percent reduction in pressure drop (0.5% for the lightest oil) is not as high as the percent reduction in viscosity (3.7% for the lightest oil). Another observation is that the reduction in viscosity and consequently in pressure drop for light crudes oils is not as significant as for the heavy crudes.
Table 2a. Pipeline pressure drop for four different crude oils without and with additive at 50 °C and oil flow rate of 7,950 m3/d
Table 2b. Pipeline pressure drop for four different crude oils without and with additive at 122 °F and oil flow rate of 50,000 bbl/day
Table 2c. Reynolds number and friction factor for the cases in Table 2 a and b
Similarly, for an oil flow rate of 15,900 m3/d (100,000 bbl/day), Tables 3a and 3b show the calculated pressure drop for the same four crude oils with varying viscosities. Tables 3a and 3b indicate that as flow rates are increased, less reduction in pressure drop is obtainable if the flow becomes turbulent. For the case of 16.4 °API, the reduction in pressure drop is 6.6% compared to 20.7 reduction when the flow rate was of 7,950 m3/d (50,000 bbl/day). The calculated Reynolds number, Moody friction factors for the cases of lower and higher oil flow rates are shown in Tables 2c and 3c, respectively.
Table 3a. Pipeline pressure drop for four different crude oils without and with additive at 50 °C and oil flow rate of 15,900 m3/d
Table 3b. Pipeline pressure drop for four different crude oils without and with additives at 122 °F and oil flow rate of 100,000 bbl/day
Table 3c. Reynolds number and friction factor for the cases in Table 3 a and b
In order to show the impact of chemical on pipeline capacity for the same pressure drop, let’s consider the heavy crude oil with 12.7 °API. As shown in Table 2a and 2b for an oil flow rate of 7,950 m3/d (50,000 bbl/day) the pressure drop without chemical was 4.684 MPa (679 psia). For the same pressure drop and using the reduced viscosity due to addition of chemicals, the capacity increases to 10,472 m3/d (65,865 bbl/day). This is equivalent of 31% increase in pipeline capacity. Similarly, referring to Tables 3a and b for an oil flow rate of 15,900 m3/d (100,000 bbl/day) for the case of without chemical, the pressure drop was 9.367 MPa (1358 psia). The calculated capacity for the same pressure drop is 20943 m3/d (131,730 bbl/day). Again, a 31 % increase in pipeline capacity is observed.
Conclusions:
The following conclusions can be made based on this case study:
The mechanisms of how drag reducing agents work are different from incorporative chemical additives. Incorporative chemical additives reduce viscosity.
Utilizing incorporate chemical additives can reduce crude oil viscosity and consequently reduces the pipeline pressure drop significantly. For existing pipelines this means an increase in the capacity of the line and/or reduction in pump power requirement.
The reduction of viscosity and pressure drop are more significant for heavier crude oils. As the oil gets lighter the effect of chemical additives is diminished. At lower temperatures the oil viscosity increases; therefore, the effect of chemical additives may become more significant for lighter crude oils, too.
The percent reduction in pipeline pressure drop is not always as large as the percent reduction for viscosity.
The incorporative chemical additives are most effective for laminar flow and/or heavier crude oils.
A total cost analysis based on hydraulic design and chemical additives with consideration for HSE (health, safety, and environment) should be made for effective design and operation.
In this Tip of the Month, we reflect back to December 2008, and get a reminder from the United States Chemical Safety Board (CSB) to remain focused on process safety and accident prevention during this time of lower oil prices.
During the economic downturn of 2008, oil prices dropped significantly. The latest drop in crude oil prices is similar. At that time, the CSB produced a video message asking companies to stay focused on process safety. That message is very relevant today.
Process Safety and Low Oil Prices
In the past, market conditions have occurred where oil prices have been low, such as we are experiencing today. Corporate cost cutting during these low oil price events have contributed to process safety incidents years later. In 2008, the United States Chemical Safety Board (CSB) Chairman John Bresland provided a reminder to oil companies that it is important to stay focused on process safety, even when prices are low. This was accomplished through a press release and a video safety message that is appropriate for this time [1].
Low oil prices, combined with striking workers at US refineries increase the challenges faced by managers to insure that process safety is a core value of the organization.
Containing overhead and operating costs during these market conditions may lead some to take shortcuts and make hasty decisions without considering all the process safety implications of these decisions. The attached press release and video safety message is as appropriate today as it was in 2008. This video message would be an excellent safety moment topic and hopefully will allow us to remain focused on process safety.
Dec 22, 2008
In First Video Safety Message, CSB Chairman John Bresland Calls for Industry to Remain Focused on Process Safety, Accident Prevention During Recession
Washington, DC, December 22, 2008 – In his first video safety message, CSB Chairman John Bresland today said that chemical companies and refineries need to continue to invest in process safety and preventive maintenance, even as the economic downturn cuts into sales and profits.
“My safety message for oil and chemical companies is clear: even during economic downturns, spending for needed process safety measures must be maintained,” Chairman Bresland stated in the message. He noted that the CSB investigation of the 2005 Texas City refinery disaster linked the accident to corporate spending decisions in the 1990s, when low oil prices triggered cutbacks in maintenance, training, and operator positions at the plant.
“Unfortunately, around the country, refinery accidents continue to be a concern,” Chairman Bresland said, pointing to three major accidents that occurred at refineries in Texas this year, including a fire at a refinery in Tyler last month that fatally burned two workers and forced the refinery to shut down for months. “Today, as gasoline prices remain low, companies should weigh each decision to make sure that the safety of plant workers, contractors, and communities is protected.”
Safety Messages are a new communication tool for the agency, consisting of short videos from the Chairman or the other board members. In the coming weeks and months, new messages will be released on a variety of current issues in chemical process safety.
“I encourage all of our stakeholders to join the discussion on YouTube.com and Blogger.com and share their thoughts about the subject of these messages,” Chairman Bresland said. Comments and ideas for future Safety Messages can also be emailed to safetymessages@csb.gov.
The CSB is an independent federal agency charged with investigating industrial chemical accidents. The agency’s board members are appointed by the president and confirmed by the Senate. CSB investigations look into all aspects of chemical accidents, including physical causes such as equipment failure as well as inadequacies in regulations, industry standards, and safety management systems.
The Board does not issue citations or fines but does make safety recommendations to plants, industry organizations, labor groups, and regulatory agencies such as OSHA and EPA. Visit our website, www.csb.gov.
For more information, contact Daniel Horowitz at (202) 261-7613 or Hillary Cohen at (202) 261-3601.
In the October 2014 Tip of the Month (TOTM), we demonstrated that Gas-Oil-Ratio (GOR) has a large impact on the capacity of crude oil gathering lines. In general as GOR increased the pressure drop increased which lowered the line capacity. In addition, at high pressures and low GOR, pressure drop was lower than the pressure drop for dead oil (solution gas is zero) because the viscosity of live oil is lower than viscosity of dead oil. This effect was bigger for the smaller line diameter.
In this TOTM, we will study the impact of solution gas (RS) on the crude oil properties in the gathering systems for one of the cases presented in the October 2014 TOTM. Specifically, the variation of the crude oil relative density and viscosity with the solution gas (RS) will be studied. Finally, the impact of solution gas (RS) on the oil and gas velocity and pressure drop along a gathering line for nominal pressure of 6900 kPag (1000 psig) and nominal pipe size of 101.6 mm (4 inches) will be demonstrated using multiphase rigorous method from a commercial simulator. The calculated properties, oil and gas velocities and pressure drops are presented in graphical format as a function of the oil stock tank volume flow rate and solution gas, RS.
For clarity, gas-oil-ratio (GOR) is defined as the total volume of gas which comes out of oil at standard conditions divided by the total volume oil at the stock tank conditions. The solution gas (RS) is defined as the volume of gas dissolved in oil divided by the volume of oil (with the same unis as GOR) but at the flowing temperature and pressure.
Case Study
For the purpose of illustration, we considered a case study for transporting a crude oil of relative density of 0.852 (°API = 34.6) at stock tank conditions combined with a gas with relative density of 0.751. The selected GORs were 0 (dead oil), 17.8, 35.6, and 89 Sm3 of gas/STm3 of oil (0, 100, 200, 500 scf/STB). The compositions of oil and gas are presented in Table 1. The oil C6+ was characterized as 30 hypothetical single carbon number (SCN) [1] ranging from SCN6 to SCN35 while the gas C6+ was characterized by 10 hypothetical SCN ranging from SCN6 to SCN15. For details of the SCN components, see Table 3.2 on page 64 of reference [1]. The mole fraction of SCN components were determined by an exponential decay algorithm [2].
Table 1. Feed composition at stock condition
The following assumptions were made:
Steady state conditions
The line is 1.601 km (1 mile) long with nominal size of 101.6 (4 inches), onshore buried line.
Segment lengths and elevation changes are presented in Table 2 and Figure 1. This elevation profile is considered to be approximately equivalent to “rolling” terrain.
Pipeline inside surface roughness of 46 microns (0.046 mm, 0.0018 inch)
Line nominal pressure 6900 kPag (1000 psig)
The feed enters the line at 15.6 ̊C (60 ̊F)
The ground/ambient temperature, is 15.6 ̊C (60 ̊F)
Water cut is 0 (no water in the feed).
Overall heat transfer coefficients of 2.839 W/m2- ̊C (0.5 Btu/hr-ft2- ̊F), for onshore
buried line (minor effect as inlet temperature = ambient ground temperature).
Simulation software ProMax [3] and using the Soave-Redlich-Kwong (SRK) Equation of State [4] for vapor-liquid equilibrium and Beggs-Brill method for two-phase pressure drop calculation [5].
Table 2. Line segment length and elevation change
Figure 1. Gathering line elevation profile
Results and Discussions:
The two phase (oil and gas) flow through the gathering line was simulated by ProMax with SRK EOS for vapor-liquid equilibria and Beggs-Brill for two phase pressure drop calculations. Figures 2A and 2B present the calculated pressure drop per unit length as a function of oil stock tank volume rate and GOR for nominal line diameter of 101.6 mm (4 inches) at nominal line pressure of 6900 kPag (1000 psig) in SI (international) and FPS (Engineering) system of units, respectively. Figures 2A and 2B indicate that as the GOR increases from 0 to 35.7 Sm3/STm3 (0 to 200 scf/STB), the pressure drop decreases but increases with further increase in GOR of 89 Sm3/STm3 (500 scf/STB) and higher.
The impact of RS on the properties of oil is demonstrated in the next section which will explain the causes of pressure drop.
Figure 2A (SI). Variation of pressure drop per unit length with oil stock tank volume rate and GOR at 6900 kPag for 101.6 mm pipe diameter
Figure 2B (FPS). Variation of pressure drop per unit length with oil stock tank volume rate and GOR at 1000 psig for 4 in pipe diameter
Figure 3 presents the bubble point pressure of the feed to the gathering line at 15.6 (60) as a function of solution gas. Figure 3 indicates that for the nominal line pressure of 6900 kPa (1000 psig), the feed is under saturated up to GOR of 51.8 Sm3/STm3 (290.5 scf/STB). For GOR greater than this value, the oil becomes saturated with gas and gas breaks out.
Figure 3. Bubble point pressure of the feed to the gathering line as a function of solution gas at 15.6 (60)
The variation of oil relative density along the line as a function of solution gas (RS), is presented in Figure 4. This figure indicates that as the RS increases, the oil relative density decreases. Figure 5 shows that as the RS increases, the oil viscosity decreases considerably. The reduction of viscosity causes pressure drop to decrease. The simulation results (Figure 3) indicated that for GOR less than 51.8 Sm3/STm3 (290.5 scf/STB), the flow is under saturated single liquid phase; however, for higher GOR the flow becomes saturated two phase (gas and liquid) which causes the pressure drop to increase. The increase in pressure drop due to higher GOR (and higher total flow rate) is more than the decrease in pressure drop due to reduction of oil viscosity as a result of solution gas. The net effect is higher pressure drop compared to dead oil (GOR = 0) pressure drop.
Figure 6 presents the variation of oil and gas velocity for two stock tank oil rate along the gathering line at 6900 kPag for 101.6 mm pipe diameter and GOR of 89.1 Sm3/STm3 (500 scf/STB). Figure 6 indicates that the oil velocity remains constant along the line but the gas velocity increases due to pressure drop in the line.
Figure 7 presents the impact of GOR on pressure drop along the gathering line at 6900 kPag for 101.6 mm pipe diameter. As it can be seen in this figure, for GOR less than 51.8 Sm3/STm3 (290.5 scf/STB) the pressure drop decreases as GOR increases but at higher GOR due to presence of two phase flow, the pressure drop increases. As the GOR increases further, the effect of elevation change diminishes compared to rise of pressure drop due to friction.
Conclusions
The following conclusions can be made based on this case study:
If the oil is under saturated the increase in solution gas (RS), reduces the oil viscosity and causes the pressure drop to decrease. For saturated oil, the increase in GOR changes the single phase liquid flow to two phase gas-liquid flow and causes the pressure drop to increase and overcome the pressure drop reduction due to lower liquid viscosity.
While increasing solution gas (RS) reduces the oil viscosity and relative density they remain almost constant along the line.
While at higher GOR the flow becomes two phase, the pressure drop due to friction becomes dominant and overcomes the elevation changes. This is more pronounced in the longer lines.
While oil velocity remains constant along the line, the gas velocity increases along the line.
Figure 4. Variation of oil relative density with solution gas (RS), Sm3/STm3 (scf/STB), along the gathering line at 6900 kPag for 101.6 mm pipe diameter
Figure 5. Variation of oil viscosity with solution gas (RS), Sm3/STm3 (scf/STB), along the gathering line at 6900 kPag for 101.6 mm pipe diameter
John M. Campbell Consulting (JMCC) offers consulting expertise on this subject and many others. For more information about the services JMCC provides, visit our website at www.jmcampbellconsulting.com, or email us at consulting@jmcampbell.com.
By: Mahmood Moshfeghian
Reference:
Campbell, J.M., Gas Conditioning and Processing, Volume 1: The Basic Principles, 9th Edition, 2nd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, 2014.
Moshfeghian, M., Maddox, R.N., and A.H. Johannes, “Application of Exponential Decay Distribution of C6+ Cut for Lean Natural Gas Phase Envelope,” J. of Chem. Engr. Japan, Vol 39, No 4, pp.375-382 (2006)
ProMax 3.2, Bryan Research and Engineering, Inc., Bryan, Texas, 2014.
Brill, J. P., et al., “Analysis of Two-Phase Tests in Large-Diameter Flow Lines in Prudhoe Bay Field,” SPE Jour, p. 363-78, June 1981.
Figure 6. Variation of oil and gas velocity for two stock tank oil rate along the gathering line at 6900 kPag for 101.6 mm pipe diameter and GOR of 89 Sm3/STm3 (500 scf/STB)
Figure 7. Impact of GOR, Sm3/STm3 (scf/STB) on pressure drop along the gathering line at 6900 kPag for 101.6 mm pipe diameter
The first pillar of Risk Based Process Safety Management is “Commitment to Process Safety.” A formalized mentoring system can ensure workforce involvement, compliance with company and regulatory requirements, increase the competency of personnel and enhance the process safety culture of the entire organization. Within this element there are several essential features that lead to a more effective process safety culture.
Providing strong leadership is critical for any organization that strives to manage the risk associated with the activities associated with process safety. Leadership is a skill that is not necessarily intuitive to managers and mentors. Leadership is a skill that can be learned.
In this Tip of the Month (TOTM), we explore process safety leadership.
This TOTM is part of a paper that was developed by John M. Campbell (JMC) Instructor/Consultants Clyde Young and John Kanengieter for presentation at the Center for Chemical Process Safety (CCPS) 9th Global Conference on Process Safety [1].
Over the last several years, significant resources have been devoted to examining the issue of process safety culture, and strong leadership has been cited as a key element to enhance a process safety culture. Study of major accidents within the oil, gas, chemical and allied industries have found that the safety culture of organizations is often proposed as a contributing factor, and development of a culture of process safety as the solution. Presentations at symposia and conferences point to enhancing culture and providing leadership as necessary to address breakdowns in process safety management systems.
The first pillar of the Center for Process Safety (CCPS) Guidelines for Risk Based Process Safety (RBPS) is “Commit to Process Safety.” Supporting this pillar is the element “Process Safety Culture”, which is defined as, “ the combination of group values and behaviors that determine the manner in which process safety is managed.” One of the four essential features of process safety culture is “strong leadership.”
Leadership
What is “leadership”? It has been described as “organizing or influencing a group to achieve a common goal”. This would intimate that the leader is a boss or manager, but is a manager necessarily an effective leader? There is considerable literature about leadership. This literature includes quotes about leadership, how to find “natural” leaders and how to develop leadership skills. There are workshops about leadership and even university degrees in leadership. If there are so many resources dedicated toward understanding and teaching leadership, why is leadership listed as something that needs to be enhanced in symposia, papers and reports that deal with managing process safety in high hazard activities? It may be because leadership and culture are considered human factors. When associated with process safety, they are known as factors that can lead to loss of the standards of consistently reliable human performance. These standards are relied on as part of an organization’s defenses against process safety incidents.
Every person working in the oil, gas, chemical and allied industries should perform their jobs under the guidance of a process safety management system. CCPS defines a management system as a “formally established and documented set of activities designed to produce specific results in a consistent manner on a sustainable basis.” Producing specific results in a consistent manner all the time requires that all personnel perform at a high level. If culture is defined simply as “the way we do things around here”, this is influenced greatly by leadership. But leadership doesn’t reside in the role of one person. Leadership needs to be imbedded within the organization with every person. This is a skill that can be learned by all and dependence on one individual with authority or one person who might be considered a “natural” leader can lead to failure of the system.
When teams cease to function effectively and breakdowns are discovered in the system to manage process safety, it is highly likely that there is a breakdown in goals, roles and expectations in the team.
Every person working in or supporting the operation of a high hazard process must be able to recite and explain the goal of every team they work with. There should never be in any doubt what every team’s goal is.
Because we may and probably do work on several teams, it is vital that we are clear of our role on each team. What is my primary function to support achieving the goal? There should never be in any doubt what every person’s role is on that team.
Does each person on the team have a concisely developed set of expectations for individual and team behavior? Is there some way for the team to check that the expectations are being met? What is the procedure for addressing deviation from expectations?
A PetroSkills client recently asked for a one-day Overview of Risk Based Process Safety Management for Upper Level Management. Four sessions of this overview have been delivered around the world to the business unit managers and their direct (team members) reports?. Leadership and working as effective teams are two elements of the session that address the issue of process safety culture in this client’s operations.
A key learning point offered by participants is that a clear understanding of goals, roles and expectations comes from leadership and exhibiting the appropriate leadership role. Many leave the session with an action item to conduct team work sessions to establish/reaffirm goals, roles and expectations.
If you would like a copy of the paper presented at the CCPS 9th Global Congress, contact PetroSkills.
John M. Campbell Consulting (JMCC) offers consulting expertise on this subject and many others. For more information about the services JMCC provides, visit our website at www.jmcampbellconsulting.com, or email us at consulting@jmcampbell.com.
By Clyde Young
PetroSkills Instructor/Consultant
Reference:
1. Clyde Young and John Kanengieter, “Process Safety Management Mentoring: Developing Leaders”, The (CCPS) 9th Global Conference on Process Safety, the Center for Chemical Process Safety , April, 2013.
A pillar of Risk Based Process Safety (RBPS) is Learn from Experience. The work we do and the processes we use to analyze our work provide significant learning opportunities to enhance process safety competency. This is a derivative of Kolb’s experiential learning cycle [1], but many times we fail to take advantage of the learning opportunities available to us unless there is an incident or a near miss.
This Tip of the Month (TOTM) will introduce a simple method for debriefing the job tasks we perform to close the loop on this cycle and capture appropriate data to develop competency, work safely and capture near miss/incident data quickly and efficiently.
Conducting a simplified job hazard analysis will ensure that all hazards are identified, managed, and mitigated prior to performing work. Performing a simple debrief at the conclusion of the work will ensure that we learn from the experience. By considering every job to be performed a learning opportunity, the experiential learning cycle can be used to identify what was done, how well it was done, and how we might improve in the future.
This Month’s Tip was recently presented at the Mary K. O’Connor Process Safety Symposium at Texas A&M University [1].
One of the pillars of the Center for Chemical Process Safety’s (CCPS) Guidelines for Risk Based Process Safety is “Learn from Experience.” What does this mean?
The elements of this pillar include:
auditing,
management review and continuous improvement,
measurement and metrics and
incident investigation.
Each of these elements provides findings, lessons and data that are useful for learning and thus changing and enhancing behaviors and attitudes. The change and enhancement will influence an organization’s culture and ultimately push the organization toward a learning culture.
These are not the only opportunities available for organizations to learn from experience. Metrics and audits can allow a general overview of process safety performance. Incident investigation insures that when reported, incident information is transmitted to all who will benefit from the learning.
The job hazard analysis process that many organizations use to identify and mitigate hazards provides a tremendous opportunity to capture data and use the experiential learning cycle if the job is debriefed properly after completion. This paper will provide guidance and explain the benefits that can be derived from debriefing completed jobs.
At the 2008 symposium, this author presented a paper entitled “Three Simple Things to Improve Process Safety Management.” One of those simple things was to conduct a formalized Job Hazard Analysis (JHA) for the tasks being performed in the life cycle of a process. That paper presented a checklist that could be used to guide personnel in the process of conducting a JHA. (See checklist at end of this paper)
Many facilities have embraced the concept of conducting JHA. They may be called something else (job safety analysis, job safety checklist, job task analysis) but the process is essentially the same. The job or task is identified and analyzed step by step. The analysis is to identify hazards that may be involved with each step and then develop strategies to mitigate the hazards. This sounds simple in theory, but in reality there are many things that can and do go wrong with this process.
To provide consistency and to make it easier to track that these analyses have been completed, standardized checklists and forms have been created that list the most common hazards that can be found with a job and logically guide the user toward identification and mitigation of hazards. Experience shows that after these forms and checklists have been used regularly, some personnel have a tendency to try and short cut the process. This leads to what is known as “pencil whipping” the JHA. In other words, personnel will complete the checklist or form without actually performing the analysis required. Familiarity with the forms and checklists may drive personnel to identify common hazards, but do little to mitigate the hazards. For example, a common checklist item is “slips, trips and fall hazards”. Personnel will identify that the ground is rutted or that there is ice on the ground, but few will actually smooth the ground or cover the ice with sand to mitigate the hazards identified.
It is generally agreed among those who supervise personnel performing JHAs that the most important part of the process is not the completion of the forms and checklists but the discussion that happens among a group performing the work. In order to focus the discussion and insure that all issues are addressed, the JHA checklist at the end of this paper can be used. The JHA checklist is not intended to replace the checklists and forms that an organization may already have in place. The JHA checklist can enhance the process by focusing a group’s thoughts on individual checklist items. By answering each question a work group should be able to identify all issues associated with any job they are conducting.
As work groups become more familiar with the JHA checklist and the process of discussing and documenting the efforts of the group, a simplified method can be adopted. By answering six key questions, a group of workers can focus discussion on the issues that are most important. The six questions and the benefits of using them include:
What are we doing? If we can’t answer this question completely and in simple terms, then we should not be doing the job. A simple explanation will insure that all members of the team are working toward the same goal.
What is the most dangerous part? If we can identify the most dangerous part of what we are doing we have identified all hazards, ranked them and determined the most dangerous part.
What will we do to protect ourselves? Answering this question ensures that all mitigation measures have been put into place and that all personnel know what is being done.
How will we know we are changing what we are doing? To answer this question effectively, we will need to be creative and analytical. Examination of the work site, knowledge of simultaneous operations, and competency in our job will be required. Anticipating potential changes will insure that we are not surprised when things do change.
What will we do about it? Again, creativity and analytical thinking are critical here. Many times we hear the phrase, “prior planning prevents poor performance”. Effectively answering this question insures that performance will be as designed.
How will we know we are finished? Review of completed job hazard analysis documents has shown that it may be difficult to determine at what point the job is complete. If the permit for the job being performed provides a scope of work like, “replace mechanical seal in hot oil pump”, once the seal is replaced, there are numerous tasks that still need to be performed before the job is complete. Numerous times the JHA does not go beyond analyzing the tasks associated with the scope of work and do not consider additional tasks; like testing, clean up and turnover to operations.
As previously mentioned, most supervisors believe that the discussion associated with this type of analysis is more important than the completion of the form used to show that the JHA has been performed.
What about the form though?
What happens at the conclusion of the job?
Does anyone review the form to determine if all the hazards were found and mitigated?
Does anyone follow up with the work group to see if anything happened that made them change the work?
How should this review be performed and what are the benefits that will be gained by this?
How can we learn from our experience?
Developing competent personnel is an ongoing process for most organizations. A great deal of literature exists on the most effective methods of developing competency in adults. Training sessions are delivered using the concept of Kolb’s theory of the experiential learning cycle. According to Kolb [2], this type of learning can be defined as “the process whereby knowledge is created through the transformation of experience.” [i] In other words, adults learn best when they are actively experiencing something and not just listening to lectures or instructor centered learning.
Experienced trainers who deliver adult learning sessions use a process of debriefing to allow reflection, reinforce learning and help the learner apply the knowledge to their life. It is generally acknowledged in the training industry that most real learning takes place in the debrief. This is the opportunity for learners to reflect and develop knowledge from the activity, in our case the job performed.
Very simply, debriefing a learning activity should focus on three questions. What? So What? Now What?
What? is the question that guides the learning toward reflection and what just happened. This question provides a starting point to discover what everyone involved experienced.
So What? is the question that leads to drawing conclusions and exploring alternate methods.
Now What? leads to future planning and continuous improvement initiatives that will be used to strengthen the organization’s culture and work processes.
If we return to question six of the job hazard analysis process, “How will we know we are done?”, the final answer for this question would be, “When we have completed the debrief of the job performed.” There are five questions that should be used for debriefing a job. These five questions, how they relate to the standard debriefing questions and the expected lessons to learn from them include:
What did we do? This is the opportunity for reflection and to insure that the job has been completed appropriately. Each member of the team should come to agreement that what is being described is what was actually done. This is the What of debriefing.
Did anything change while doing the job? Reflection on this question will lead the team to determine if the job was actually performed as it was initially described and analyzed. This is the question that will also lead to identify incidents for investigation. If anything unusual occurred during the task, reporting should be more efficient because the incident will be fresh in everyone’s mind. Capturing these incidents and changes now will help modify future work orders and insure that we learn something from this experience. This is the So What of the debriefing cycle.
Did anybody get hurt? This question should be answered with all personnel examining themselves for strains, pulled muscles, bumps, bruises, cuts, scrapes, twisted joints, twinges in the back and a general self examination for good health. Any small injury or potential illness should be recorded here. This will insure that a worker does not leave the job without reporting an injury or illness, and then visit a medical provider later because something cropped up. Having someone discover they have been injured after leaving the worksite is a problem for managers. This allows measures to be taken early to manage the injury or illness for reporting purposes. Here and the next question is where more exploration of the “What” is performed.
Did anybody come close to getting hurt? This is the question that will capture near miss incidents quickly. Near miss reporting programs fail for numerous reasons. Lack of understanding, lack of motivation, blaming the reporter, and convenience of reporting are reasons that near misses may not be reported. Reflection and discussion about the completed job will insure that any near miss is reported quickly. This will lead to creation of a more comprehensive database that can be used to predict trends and identify problems areas in processes.
What would we do differently? This is the question that will tie everything together into a plan for the future. Recommendations and action items should be generated from this final question so that future jobs can be analyzed with more speed and efficiency. Potential training and competency development issues may be discovered. Procedures for modification may be identified. Latent conditions that are not readily apparent may be identified and mitigated before they become active failures.
The Now What of the debriefing cycle is:
Conducting an effective job task analysis and following with an effective debriefing of the job will yield several benefits.
Competency gaps of personnel associated with the work will be identified.
Training topics and on the job mentoring for personnel with these identified gaps, can be more quickly delivered.
Procedural modifications that are necessary to insure that work is performed safely and efficiently will be quickly identified and addressed.
Potential process safety incidents will be quickly identified and investigated.
Near miss incidents will be reported quickly and the organization’s near miss/incident database will be enhanced.
The process described in this paper can be expanded to any job and any work group. Consider an engineering team who is working on the design of a new process to be considered for construction. Conducting an effective job task analysis in the beginning stages of the project will insure that roles, goals and expectations are addressed and known. Conducting an effective debrief at the conclusion, or even at selected stages of a project, will enhance the project team’s effectiveness and insure that all team members are always striving to meet the goal of the project. The attached checklist for engineering projects, at the end of this paper, may be helpful for focusing a team’s efforts.
Opportunities exist in all phases of operations and in all activities performed to keep processes safe. It is important that all personnel be aware that learning from experience happens every day and these lessons learned need to be captured and stored for future use.
1. Young, Clyde. ,” Debrief: The experiential learning cycle, process safety competency, safe work practices, identifying and reporting of near miss/incident data”, Mary K. O’Connor Process Safety Symposium, Texas A&M University, October 29.
2. Kolb, David A. Experiential Learning: Experience as the Source of Learning and Development. Prentice-Hall, Inc., Englewood Cliffs, N.J. 1984.
Job Hazard Analysis Checklist
1. PROCEDURES
·What are the procedures for the task?
·What is unclear about the procedures?
·What order will we use these procedures?
·What permits are needed for hazard controls?
2. EQUIPMENT AND TOOLS
·What are the right tools for the job?
·What is the correct way to use them?
·What is the condition of the tool?
3. POSITIONS OF PEOPLE
·What could we be struck by?
·What could we strike ourselves against?
·What can we get caught in/on/between?
·What are potential trip/fall hazards?
·What are potential hand/finger pinch points?
·What extreme temperatures will we be in/around?
·What are the risks of inhaling, absorbing, swallowing hazardous substances?
·What are the noise levels?
·What electrical current/energized system could we come in contact with?
·What would be a cause for overexerting ourselves?
4. PERSONAL PROTECTIVE EQUIPMENT
·What is the proper PPE?
Hard hat, glasses/goggles, ear plugs, gloves, steel toe boots, respiratory system, fire retardant clothing
5. CHANGING THE COURSE OF WORK
·What would cause us to have to stop or rearrange the job?
·What would cause us to change our tools or equipment?
·What would cause us to have to change our position?
·What would cause us to have to change our PPE?
YOU HAVE THE RIGHT AND
THE OBLIGATION TO
STOP UNSAFE ACTS
ENGINEERING JOB ANALYSIS
1. PROCEDURES
·What are the procedures for the task?
·What is unclear about the procedures?
·In what order will we use these procedures?
·What is the proper timeline for these procedures?
·What permits or permissions are needed for job controls?
2. EQUIPMENT, TOOLS, DOCUMENTS
·What are the right tools for the job? (software, simulators, matrixes, checklists, worksheets…)
·What is the correct way to use them?
·What forms will be needed for the job?
·What documents will we need to produce?
·What else do we need to know?
3. INTERACTION WITH PEOPLE
·What other departments need to know about this task?
·Who are the personnel that need to know?
·What other departments will supply information for this task?
·Who are the personnel who will supply that information?
·What could prevent other personnel or departments from supplying what we need?
·What could prevent us from supplying what other departments need?
4. CHANGING THE COURSE OF WORK
·What would cause us to have to stop or rearrange the job?
·What would cause us to change our tools or equipment?
·What would cause us to have to change our interaction with people?
Stainless steel is a family of corrosion resistant steels containing chromium in which the chromium forms a passive film of chromium oxide (Cr2O3) when exposed to oxygen [1]. This phenomenon is called passivation and is seen in other metals, such as aluminium and titanium.
The film layer is impervious to water and air and quickly reforms when the surface is scratched. This protects the metal beneath – preventing further surface corrosion. Since the layer only forms in the presence of oxygen, corrosion-resistance can be adversely affected if the component is used in a non-oxygenated environment e.g. underwater bolts on a platform support structure.
Such passivation only occurs if the proportion of chromium is high enough and is normally achieved with addition of at least 13% (by weight) chromium. Progressively higher levels of corrosion resistance and strength is achieved by the addition of other alloying elements – each offering specific attributes in respect of strength and corrosion resistance.
Classification issues
The need to classify stainless steel has led to a fundamental problem of which method to use. Probably the best known system derives from of the Society of Automobile Engineers (SAE) e.g. 316 Cr/Ni/Mo 17/12/2. This is interpreted as stainless steel containing the proportions of 17% chromium, 12% nickel, and 2% molybdenum.
However, the waters are somewhat muddied by a variety of international and country-based systems that include EN (European Norm); and UNS (Unified Numbering System). For example, SAE 304 Cr/Ni 18/10 stainless steel is EN 1.4301 which is UNS S30400.
Stainless steels may also be graded into five basic families or phases determined by their crystalline structure: the stable phases austenitic or ferritic; a duplex mix of the two; the martensitic phase created when some steels are quenched from a high temperature; and precipitation-hardenable.
Ferritic stainless steel
In ferritic stainless steel, the iron and chromium atoms are arranged in what is termed a body-centred cubic structure in which the atoms are arranged on the corners of the cube and one in the centre (Figure 1). As well as being ferro-magnetic, ferritic stainless steel exhibits very high stress corrosion cracking resistance.
Ferritic stainless steels are plain chromium (10.5 to 18%) grades characterized by moderate corrosion resistance and poor fabrication properties. These characteristics may be improved with the addition of molybdenum; some, aluminium or titanium.
Austenitic stainless steel
With the addition of nickel, the properties change dramatically. As shown (Figure 3) the atoms are re-arranged so that they occur on the corners of the cube and also in the centre of each of the faces. In this manner it becomes what is termed austenitic stainless steel.
It can thus be seen from Table 1 that unless you are specifically looking for a ferro-magnetic material, austenitic stainless steel would be the most obvious choice. Indeed this is borne out by the fact that austenitic stainless steels account for about 70% or more of all stainless steel used worldwide – with ferritic stainless steels making up about 25%. The other families each represent less than 1% of the total market.
Austenitic stainless steels are designated by numbers in the 200 and 300 series.
Series 300
The relationship between the 300 austenitic grades is shown in Figures 4.
The basic grade 304 contains about 18% chromium and 8% nickel (often referred to as 18/8) and range through to the high alloy or ‘super austenitics’ such as 904L and 6% molybdenum grades.
Additional elements can be added such as molybdenum, titanium or copper, to modify or improve their properties, making them suitable for many critical applications involving high temperature as well as corrosion resistance. This group of steels is also suitable for cryogenic applications because the effect of the nickel content in making the steel austenitic avoids the problems of brittleness at low temperatures, which is a characteristic of other types of steel.
Generally, the 300 grade alloys are subject to crevice and pitting corrosion.
Low-carbon versions, (indicated by the letter suffix L) include 304L, 316L and 317L, in which the carbon content of the alloy is below 0.03%. This reduces the effect of ‘sensitisation’ in which chromium carbides precipitate at the grain boundaries due to the high temperatures involved in welding. The relatively high nickel content also inhibits the brittleness exhibited by ferritic materials at low temperatures and thus makes austenitic steels suitable for cryogenic applications.
200 series
We have seen earlier how the addition of nickel is used in the creation of the classic chrome-nickel 300 series austenitic stainless steel.
The reduced nickel content of the 200 series chrome-manganese grades makes them significantly cheaper. However, depending on their chemistry, they also offer good formability (ductility) and/or strength. Indeed, certain grades (201, 202 and 205 series) even offer about 30% higher yield strength than the classic 304-series chrome-nickel grade – allowing designers to cut weight (Table C.2).
Reducing nickel, on the other hand, reduces the maximum chromium content possible in the alloy. Less chromium means less corrosion resistance and a consequent narrowing of the range of applications for which the material is suitable.
A word of warning comes from the International Stainless Steel Forum (ISSF). Continuous pressure to cut costs, especially from the Asian market, has resulted in the development of austenitic grades ever lower in nickel and chromium, often not covered by international codes or specifications. In fact, numerous chrome-manganese grades are company-specific and identified simply by a title given to them by the producer.
Duplex stainless steels
Duplex stainless steels [6] are a mixture of austenite and ferrite microstructures that combine some of the features of each class:
resistance to stress corrosion cracking – but inferior to ferritic steel;
superior toughness to ferritic steel – but inferior to austenitic steel;
roughly twice the strength of austenitic steel;
superior resistance to pitting, crevice corrosion and stress corrosion cracking;
high resistance to chloride ions attack; and
high weldability.
These features are achieved by adding less nickel than would be necessary for making a fully austenitic stainless steel. Thus, Grade 2304 comprises 23% chromium and 4% nickel whilst Grade 2205 comprises 22% chromium and 5% nickel – with both grades containing further minor alloying additions.
On the negative side, austenitic-ferritic duplex stainless steels are only usable between temperature limits of about -50°C and 300°C – outside which they suffer reduced toughness.
Martensitic stainless steel
Named after the German metallurgist, Adolf Martens, the martensitic Grade 400 series (Figure 5) are low carbon (0.1–1%), low nickel (less than 2%) steels containing chromium (12 to 14%) and molybdenum (0.2–1%).
Stainless steels hardened by transformation to martensite are tempered to give the desired engineering properties. At high temperatures they have an austenitic structure that is transformed into martensitic structure upon cooling to room temperature. Unfortunately, this tempering can influence corrosion susceptibility. For example, corrosion susceptibility of type 420 stainless steel is at its maximum when the alloy is tempered at temperatures in the range of 450° to 600°C. So, aalthough not as corrosion-resistant as the 200 and 300 classes, martensitic stainless steels are magnetic, extremely strong (if not a little brittle), highly machinable, and can be hardened by heat treatment.
Martensitic stainless steels are subject to both uniform and non-uniform attack in seawater. And the incubation time for non-uniform attack in even weak chlorides is often only a few hours or days.
These chromium- and nickel-containing steels can be precipitation hardened to develop very high tensile strengths. Precipitation-hardening stainless steels are usually designated by a trade name rather than by their AISI 600 series designations.
The most common grade in this group is ‘17-4 PH’, also known as Grade 630, with a composition of 17% chromium, 4% nickel, 4% copper and 0.3% niobium. The main advantage of these steels is that they can be supplied in the ‘solution treated’ condition – in which state the steel is just machinable. Following machining, forming, etc. the steel can be hardened by a single, fairly low temperature ‘ageing’ heat treatment that causes no distortion of the component.
Precipitation hardening generally results in a slight increase in corrosion susceptibility and an increased susceptibility to hydrogen embrittlement.
By: Mick Crabtree
References
1. T. Sourmail and H. K. D. H. Bhadeshia, ‘Stainless Steels’, University of Cambridge.
3. ‘Stainless Steel and Corrosion’, ArcelorMittal, Stainless Europe.
4. A.U. Malik, M. Kutty, Nadeem Ahmad Siddiqi, Ismaeel N. Andijani, and Shahreer Ahmad, ‘Corrosion Studies on SS 316 L in low pH high Chloride product water medium’, 1990.
5. ‘The Stainless Steel Family’, International Stainless Steel Forum.
6. API Technical Report 938-C: ‘Use of Duplex Stainless Steels in the Oil Refining Industry’.
In this Tip of the Month, we explore how process safety competency can be enhanced through mentoring programs.
This TOTM is the paper that was developed by JMC Instructor/Consultants Clyde Young and Keith Hodges presentation at the Center for Chemical Process Safety (CCPS) 8th Global Conference on Process Safety in April, 2012. The paper will also be published in the AIChE (American Institute of Chemical Engineering) publication, “Process Safety Progress.”
Commit to Process Safety is the first pillar mentioned in “Guidelines for Risk Based Process Safety Management”, published by CCPS. This pillar is supported by five elements. One of the elements is Process Safety Competency, which is associated with efforts to maintain, improve and broaden knowledge and expertise.
In Greek mythology, Odysseus, King of Ithaca went to fight in the Trojan Wars. Before he left, he entrusted his son Telemachus to the care of his old and trusted friend MENTOR. It was some ten years before father and son were reunited and during this time the development and care of his son was with Mentor.
What is often missing from historical accounts is that it is Athene, the Goddess of Wisdom, who appears to Telemachus in the likeness of Mentor and gives advice, encouragement and spiritual insight.
Since then, the word Mentor has become synonymous with trusted advisor, friend and teacher, a wise person.
Demographic studies of the oil and gas processing industry indicate that a large number of people are retiring and being replaced by younger, less experienced personnel. This presents a challenge to the industry. A wise mountaineer once stated, “Good judgment comes from bad experiences.” With the influx of less experienced personnel, it would be shameful to have their good judgment developed from their bad experiences. Especially since these bad experiences can be catastrophic.
Organizations in the industry have spent considerable resources recruiting the best talent available and most have a competency development program that these new workers enter. The program will generally include a step to have a more experienced person provide feedback on the worker to assess competency in the job. Well-developed and resourced competency development programs will have a Mentor assigned to the worker.
What does this really mean and how can an organization insure that process safety competency is developed in all personnel, even if process safety activities are not the primary role?
This TOTM will provide some guidance and best practices for establishing Mentoring programs with an emphasis on developing process safety competency in the younger, less experienced workforce.
The role of Mentor involves teaching, helping, protecting, challenging, motivating, guiding, coaching, listening, and providing career guidance; it falls short of counseling. Counseling is the provision of professional psychological help and advice and chosen Mentors would be foolhardy to attempt such a role without extensive training.
Mentoring is usually a formal or informal relationship between two people, a Mentor (usually and preferably outside the Mentee’s area of supervision) and a Mentee. The Mentor can also be provided from an external organization. This can be preferable especially if there is any hint of competition between the Mentors and Mentees (e.g. working in the same department as peers). There are different rules of engagement if the external option is taken and this is outside the scope of this paper. Peer Mentoring can be a useful option, especially if a peer Mentor has specific skills and qualifications.
Using a Mentee’s supervisor within a discipline should be avoided as there could be a conflict of interest. The Mentor may be Mentoring one day and disciplining the next, This is not conducive to building trust, which is an important ingredient in the Mentoring process.
Mentoring should not be substituted for conventional classroom or computer-moderated training. It enhances traditional training by allowing the Mentee to learn from experienced colleagues within the working environment.
Choosing a Mentor
The choice of Mentors is an important aspect of a program and managers should first be satisfied that a Mentor not only has the required technical skills, but also has the ability to convey those to others in an efficient and effective way. Competency associated with Mentoring skills does not necessarily come naturally to everyone with highly competent technical skills. A key skill to insure effective process safety is communication with all disciplines that could have an impact on the process.
Mentor Program
It is foolhardy to think that just putting together a pool of people as Mentors and pairing them with Mentees is going to be an effective way to put a Mentor program together. It takes planning and needs structure. There has to be an organizational aim for the program with measurable objectives. The Mentor should be provided with these and a list of roles and responsibilities, which they should fully comprehend.
There should be a selection process for Mentors and organizations must recognize that a training program may have to be created for selected Mentors.
Ideally the Mentee should be able to select the Mentor from a pool of people in the organization; management, the training department or HR should not pair them. Mentors should have the option to refuse the role should they feel that it would not be appropriate.
Mentoring and Process Safety
A Mentoring program is not to be approached in a haphazard fashion if the goal is to develop competent personnel. A Mentoring program is much like a process safety management system. The Center for Chemical Process Safety (CCPS) guidelines for Risk Based Process Safety Management (RBPSM) defines a management system as, “A formally established and documented set of activities designed to produce specific results in a consistent manner on a sustainable basis.” The Mentoring program should be formalized, documented and designed to produce specific results. The specific results are competent personnel associated with process safety.
Mentees within a program may have been chosen because they are targeted to fill a key role within the organization. This role could be a technical position that requires narrow skills in a field or a supervisory position of either engineering personnel or operations personnel. The competency levels associated with process safety that are required will be highly dependent on the role in the organization. The Mentor/Mentee relationship should keep this in mind as the process progresses.
An effective Mentoring program that includes process safety as a key component will yield numerous benefits to the organization. A Mentor with wide professional and technical expertise should have considerable experience in areas that involve process safety. A Mentor that truly understands the concepts of risk based process safety will be invaluable to a Mentee with less experience. Consider the pillars of RBPSM and some of the elements within each pillar.
Commit to Process Safety
Elements of this pillar include:
Process safety culture
Compliance with standards
Process safety competency
Workforce involvement
Stakeholder outreach
A simple definition of culture is, “How we do things around here.” Organizations strive to develop a learning culture that seeks hazards and solutions on a continuous basis. It is imperative that Mentees are provided awareness level training on the organization’s culture and the Mentor will be given training on how to act as the example. Two significant benefits will come from this. The Mentors will examine their own actions within the culture and insure that they are setting a good example. The Mentee will question why and how activities are accomplished and learn his/her role within the organization’s culture, which should accelerate the Mentees contribution through self-awareness.
It will be difficult for a less experienced worker to learn the things required to insure compliance with all applicable standards. An effective Mentor should always guide the Mentee toward the correct answer associated with compliance but not necessarily answer the question of compliance. The guidance and allowing the Mentee to find the answer will insure that the learning associated with compliance will be retained long after the answer is discovered.
Process safety competency of the Mentee will be enhanced significantly, but only if the Mentor insures that the Mentee is directed to the appropriate resources for this. The Mentor does not necessarily have to be considered a process safety expert. The Mentor does have to be aware that some process safety issues require a level of expertise that will be found elsewhere. And sometimes those resources may be outside the organization.
For a process safety management system to thrive, staff members at all levels of the organization must take an active role. The role taken needs to be identified and metrics established to show participation in the role. A Mentor can provide guidance and suggestions so that the Mentee is consistently working toward the goals of the process safety management system. Appropriately timed reviews of progress associated with established process safety metrics should be scheduled and conducted.
Stakeholders include outside contractors, shareholders, community members and partners in joint ventures. A Mentee may be involved with negotiations and planning activities associated with all kinds of stakeholders. A Mentor’s experience in the industry and the organization can be very useful to insure that all stakeholder interests are addressed.
Understand Hazards and Risks
Elements of this pillar include:
Process knowledge management
Hazard identification and risk analysis
Development of a Mentee’s competency in this pillar of RBPSM could be the Mentor’s most important role. Insuring that the correct process knowledge is developed and managed appropriately is a critical activity that the Mentee strives for. There is no need for a Mentee to learn from mistakes if a Mentor can provide clear guidance on this pillar.
It is within these two elements that mistakes can lead to catastrophic events. Having an incorrectly sized relief valve installed in a process or not anticipating the consequences of failure of controls is not acceptable. The Mentor and Mentee should routinely conduct discussions about these elements.
Contract services are utilized a great deal for design of new and modified facilities. A Mentor who has significant experience in this area can provide the Mentee advice and guidance for overseeing these projects. Oversight by a qualified company representative will insure that all issues associated with a project have been addressed.
Providing resources during the conduct of Process Hazard Analysis (PHA) studies is a challenge for many organizations. This is especially true considering the demographics of the industry at this time. More experienced personnel have moved on. PHA team members with significant experience are critical to the success of a PHA. A Mentee who is assigned to a PHA team may or may not work side by side with their Mentor. If the assigned Mentor is also a member of the PHA team, this may prove advantageous. As the role of Mentor is to provide guidance and direction to new and developing staff, the PHA is an excellent environment to do just that. The structure of the PHA provides an opportunity to guide the Mentee in the proper way to identify hazards, develop measures to mitigate those hazards and work as a team member in a formalized setting.
Manage Risk
Within this pillar, a Mentee will benefit from the guidance of an experienced Mentor to become proficient at what might be considered the day-to-day activities associated with their job. Elements are:
Procedures
Safe work practices
Asset integrity
Contractors
Training and performance
Management of change
Operational readiness
Conduct of operations
Emergency management
Sometimes organizations will assign a younger, less experienced person to a supervisory position in operations to “season” them. Studies have shown that a great number of incidents occur during normal operations. Having a Mentor with significant operations experience will accelerate the “seasoning” process and insure that the problems associated with day-to-day activities do not lead to a catastrophic incident.
Working in operations supervision will certainly expose the Mentee to many issues associated with personal interaction. Dealing with people may be one of the most difficult tasks undertaken. Having the ear of a Mentor can be helpful as the Mentee develops his/her skills in this area.
Learn From Experience
There is no reason that a young professional cannot learn from the experience of others. To pass along the experience and knowledge that has been gained over the years is the focus of a Mentoring program. Hopefully, the Mentee will not have to experience a catastrophic incident to learn from experience.
Elements within this pillar are:
Incident investigation
Measurement
Audits
Management review and continuous improvement
Having a Mentor available to help review near miss reports, incident investigations, audit findings and metrics associated with process safety can provide the Mentee with a “cold eye” review of issues that are the Mentee’s responsibility to address. Often a wiser, more experienced Mentor will have experienced some of the same things that are being discovered under the Mentee’s watch. In this case, issues should be able to be addressed quickly and more efficiently.
Troubleshooting
All processes within the industries we work have been designed to operate in a specified manner. This manner includes specific temperatures, pressures, flow rates and levels. Defining these specific parameters establishes “normal” for these processes. Operating processes in a “normal” manner reduces the likelihood of a catastrophic incident. Deviation from “normal” is not acceptable and identifying this deviation and taking the steps required to return to normal requires experience and knowledge. This is known as troubleshooting. Process safety management is a system that establishes “normal” and provides directions on maintaining “normal”. Personnel with effective troubleshooting skills will also work efficiently within an organization’s process safety management system.
A formalized, well established Mentoring program for younger, less experienced personnel entering the business enhances everyone’s troubleshooting skills. The Mentee has someone (the Mentor) available to query about issues seen and the Mentor is challenged to insure the advice and guidance provided is correct and useful.
Attaining high-level competency in a job requires training and then performing the job for a period of time. Accelerating the path to high-level competency is a significant goal of a formalized Mentoring program.
Conclusion
At the beginning of this TOTM, it was stated that the word Mentor has become synonymous with trusted advisor, friend and teacher, a wise person. Process safety management has become synonymous for reducing the risk associated with the activities performed in our industries.
Risk is often viewed differently from individual to individual. A person’s perception of risk may change with familiarity. Having a trusted advisor for younger, less experienced personnel, to help identify and provide suggestions for mitigation of hazards, in all their forms, is a strong competency development tool for any organization. Personnel will be developed quicker and more efficiently. Experienced personnel are one of a company’s most valuable resources. Acting as a Mentor can be the best use of this resource and will provide a challenge that some people thrive on.
Any organization that truly strives for a generative safety culture should do whatever it takes to implement a process safety-Mentoring program. The benefits will be seen and reaped for years to come.
John M. Campbell Consulting (JMCC) offers consulting expertise on this subject and many others. For more information about the services JMCC provides, visit our website at www.jmcampbellconsulting.com, or email us at consulting@jmcampbell.com.
In the November tip of the month (TOTM) we presented a single-stage compressor calculation result of a case study. We compared the rigorous method with the values from the short cut methods. The rigorous method was based on the Soave-Redlich-Kwong (SRK) for calculating the required enthalpies and entropies.
In this TOTM, we will present a case study of multistage stage compression with interstage cooling using the rigorous method. The rigorous method will be based on the Soave-Redlich-Kwong (SRK), Peng-Robinson (PR), Lee Kesler (LK) and Benedict-Webb-Rubin-Starling (BWRS) equations of state. The K-values, enthalpies, and entropies are calculated by these EOSs to perform vapor-liquid-equilibrium (VLE) and the energy balance calculations to determine the power requirement, the discharge temperatures and the cooling load requirements. We will compare the compressor power and cooling load requirements based on the rigorous equations of state.
Power Calculations
The theoretical power requirements are independent of compressor type; the actual power requirements vary with the compressor efficiency. In general the power is calculated by:
From a calculation viewpoint alone, the power calculation is particularly sensitive to the specification of flow rate, inlet temperature and pressure, and outlet pressure. Gas composition is important but a small error here is less important providing it does not involve the erroneous exclusion of corrosive components. A compressor is going to operate under different values of the variables affecting its performance. Therefore the most difficult part of a compressor calculation is specification of a reasonable range for each variable and not the calculation itself. Reference [1] emphasizes that using a single value for each variable is not the correct way to evaluate a compression system.
Normally, the thermodynamic calculations are performed for an ideal (reversible) process. The results of a reversible process are then adapted to the real world through the use of efficiency. In the compression process there are three ideal processes that can be visualized: 1) an isothermal process, 2) an isentropic process and 3) a polytropic process. Any one of these processes can be used suitably as a basis for evaluating compression power requirements by either hand or computer calculation. The isothermal process, however, is seldom used as a basis because the normal industrial compression process is not even approximately carried out at constant temperature.
Step-by-Step Computer Solution
For known gas rate, pressure (P1), temperature (T1), and composition at the inlet condition and discharge pressure (P2) or compression ratio, computation of compressor power requirement is based on an EOS using a computer and involves two steps:
Determination of the ideal or isentropic (reversible and adiabatic) enthalpy change of the compression process. The ideal work requirement is obtained by multiplying mass rate by the isentropic enthalpy change.
Adjustment of the ideal work requirement for compressor efficiency.
The step-by-step calculation based on an EOS is outlined below.
Assume steady state, i.e. and the feed composition remain unchanged.
Assume isentropic process, i.e. adiabatic and reversible
Calculate specific enthalpy h1=f(P1, T1, and composition) and suction specific entropy s1=f(P1, T1, and composition) at the suction condition by EOS
For the isentropic process . Note the * represents ideal value.
Calculate the ideal specific enthalpy at outlet condition for known composition, P2 and .
The ideal work is
The actual work is the ideal work divided by efficiency or
The actual enthalpy at the outlet condition is calculated by
The actual outlet temperature is calculated by EOS for known h2, P2, and composition.
The efficiency of the compressor, and hence, the compression process obviously depends on the method used to evaluate the work requirement. The isentropic efficiency is in the range of 0.70 to 0.90.
If the manufacturer provides the compressor head curve and efficiency curve, the head is determined from the actual gas volume rate at the inlet condition. Second, from the head, the actual work, discharge pressure and finally the discharge temperature are calculated.
Case Study
The gas mixture with the composition shown in Table1 at 105 °F (40.6 °C) and 115 Psia (793 kPa) is compressed to 1015 psia (7000 kPaa) using a multistage centrifugal compressor. The total feed gas volumetric flow rate was 101 MMSCFD (2.86×106 Sm3/d). This is the same feed used in the November TOTM.
Table 1. Feed gas analysis
A simplified process flow diagram is shown in Figure 1. The dry feed gas is saturated with water, passed through a scrubber (knockout drum) before entering the first stage of compressor. Each compression stage is followed by cooling and subsequent knockout drum before entering the next stage. An equal compression ratio of 3 was used for each stage. The polytropic efficiency of 86, 80, and 79 % based on the actual inlet volumetric rate (from Figure 13.23 of GPA Data book [2]) was specified for stages 1, 2, and 3 respectively. After each compression stage, the gas was cooled to the feed temperature of 105 °F (40.6 °C).
Figure 1. Three-stage compression with interstage cooling
Results and Discussions
The feed composition, suction temperature and pressure, volumetric flow rate at standard condition along with the compressor polytropic efficiency for each stage, and pressure drop for each cooler were specified. For this study, the above PFD was simulated using the Soave-Redlich-Kwong (SRK) [3], Peng-Robinson (PR) [4], Lee Kesler (LK) [5] and Benedict-Webb-Rubin-Starling (BWRS) [6] equations of states. These data were entered into the ProMax software [7] to perform the rigorous calculations based on the EOS. The program calculated discharge temperature, power for each stage, and cooling loads for each cooler. For the actual gas flow rate at the inlet condition, the polytropic efficiency was specified from the GPA data book. The calculated results for the four EOSs are presented in Table 2 (bold numbers with white background).
Table 2 (FPS units). Summary of the rigorous results for four EOSs using ProMax
The bold numbers with white background are the calculated values
Table 2 (SI Units). Summary of the rigorous results for four EOSs using ProMax
The bold numbers with white background are the calculated values
For the case of LK EOS, the wet feed volume flow rate at standard condition to the first stage of compressor is lower than the other cases because this EOS has not been revised to handle water content.
For the case studied, Table 2 indicates that there is 0.8 to 1.4 percent deviation in total compression power requirements among these 4 EOSs. The deviation in total heat removal using different EOSs is 1.7 to 2.2 percent. For facility type calculations and planning purposes, these differences are negligible. However, for cases with large power requirement, these small differences in terms of total HP or kW could be significant; therefore, care should be taken to choose an appropriate EOS for handling VLE calculations and accurate predictions of enthalpy and entropies for the system under consideration. The deviation range could be different for other cases depending on the flow rates, condition composition and compression ratio.
John M. Campbell Consulting (JMCC) offers consulting expertise on this subject and many others. For more information about the services JMCC provides, visit our website at www.jmcampbellconsulting.com, or email your consulting needs to consulting@jmcampbell.com.
By Dr. Mahmood Moshfeghian
References:
Maddox, R. N. and L. L. Lilly, “Gas conditioning and processing, Volume 3: Advanced Techniques and Applications,” John M. Campbell and Company, 2nd Ed., Norman, Oklahoma, USA, 1990.
Gas Processors Association Data Book, 12th Edition, GPA, Tulsa, Oklahoma.
Soave, G., Chem. Eng. Sci., Vol. 27, pp. 1197-1203, 1972.
Peng, D. Y., and Robinson, D. B., Ind. Eng. Chem. Fundam., Vol. 15, p. 59, 1976.
Lee B.I., Kesler M.G., “A Generalized Thermodynamic Correlation Based on Three-Parameter Corresponding States”, AIChE J., 21(3), 510-527, 1975
Starling, K. E., Fluid Thermodynamic Properties for Light Petroleum Systems, Gulf Publishing Co., Houston, 1973.
ProMax 3.2, Bryan Research and Engineering, Inc, Bryan, Texas, 2011.
= Mass flow rate
= Gas relative density; ratio of gas molecular weight to air molecular weight
