Gpsa Engineering Data Book Free Download Pdf

[Marva Richardt]

Thesolubility of acid gases in TEG solution has been the subject of two previous Tips of the Month, (June 2012 and July 2012). In these instances, the focus was on gas streams with maximum acid gas partial pressure of 100 psia (690 kPa) and TEG concentrations of 95 and 100 wt%. This is typical for dehydration of sour gas streams.

This month, the focus shifts to the case where the gas is pure CO2, with partial pressures (and system pressures) ranging up to 800 psia (5 500 kPa), and pure TEG. These conditions approximate the dehydration of high-CO2 content gases in a CO2 enhanced oil recovery project, or perhaps, CO2 from an industrial source that is to be compressed, transported and sequestered.

Two algorithms have been developed to predict the CO2 solubility in pure TEG. One algorithm uses the same format as the Mamrosh-Fisher-Matthews [1] Solubility Model presented in the June 2012 and July 2012 Tips of the Month. In order to improve the correlation for pure CO2 and TEG, the equation parameters (A through D) were regressed using data extracted from Figure 20-76 of the GPSA Engineering Data Book [2]. The equation and new parameters are presented below.

The original Mamrosh et al. [1] model, was first applied to data extracted from GPSA Figure 20-76 [2]. Average Absolute Percentage Deviation (AAPD) was greater than 6.5% and the Maximum Absolute Percentage Difference for the data set exceeded 34%. To improve accuracy, a multi-parameter regression was performed using data from Figure 20-76. The new values for Parameters A, B, and D (C was set to zero and the original value of E was used) are presented in Table 1 below.

The accuracy of the MODIFIED Mamrosh et al. [1] model was evaluated against the data extracted from Figure 20-76 of Gas Processors Suppliers Association Engineering Data Book, 12th Edition [2]. The summary of our evaluation results is shown in Table 2.

Figure 1 presents the data extracted from GPSA Figure 20-76 [2] for the solubility of pure CO2 in 100% TEG, and the predicted values from the MODIFIED Mamrosh et al. equation. GPSA data points are denoted as symbols: Equation results are shown as solid lines.

Overall the accuracy is very good. At 15 psia, the error looks significant, and the absolute percentage deviation is as high as 10%. However; the actual solubility is small, so the magnitude of the error in physical terms is insignificant.

A 6-parameter empirical model was developed by regression of the data extracted from GPSA Figure 20-76 [2]. The general form of the equation is presented as Equation (2) and the values for the six parameters are provided in Table 3. The model is suitable only for pure CO2 and 100% TEG.

The accuracy of the proposed model was evaluated against the data extracted from Figure 20-76 of Gas Processors Suppliers Association Engineering Data Book, 12th Edition [2]. The summary of our evaluation results is shown in Table 3.

Figure 2 presents the data extracted from GPSA Figure 20-76 [2] for the solubility of pure CO2 in 100% TEG, and the predicted values from the proposed Model. GPSA data points are denoted as symbols: Equation results are shown as solid lines. Also included in Figure 2 are nine data points from GPA Technical Publication TP-9 [3]. These data points are actual values measured for pure CO2 and 100% TEG at three pressures. Note the TP-9 data were not used in the regression process.

The accuracy of the proposed Model is slightly better than the MODIFIED Mamrosh et al. model. Average and Maximum Absolute Percentage Deviations are both reduced. As with the MODIFIED Mamrosh et al. model, the greatest percentage error corresponds to the low pressure case (15 psia or 104 kPa) where the solubility is very small, so the actual deviation is likely insignificant for most engineering calculations.

Figure 3 presents the selected data from GPA RR 183 [4] for the solubility of pure CO2 in 100% TEG, and the predicted values from the Modified Mamrosh et al. Model and the Proposed Model. These GPA data were not used in regressing either of the two models parameters.

Two new algorithms have been developed to predict the solubility of pure CO2 in 100% TEG. Both algorithms were developed by regressing data extracted from Figure 20-76 of the Gas Processors Suppliers Association Engineering Data Books [2]. It should be noted that the Figures in GPSA are attributed to Ed Wichert, Sogapro Engineering with all rights reserved.

The first algorithm is a Modified form of the Mamrosh et al. model [1]. The original model was presented and evaluated for CO2 concentrations of up to 10 mole percent in the June and July 2012 Tips of the Month. However, model predictions for pure CO2 and 100% TEG produced an average absolute percentage deviation (AAPD) of more than 6.5%, and a Maximum Absolute Percent Deviation (MAPD) of more than 34% compared with data extracted from Figure 20-76 of the GPSA Engineering Data book [2]. To improve accuracy, the equation parameters were regressed with data points extracted from Figure 20-76. The Modified Mamrosh et al. model more accurately reproduces the curves in Figure 20-76, with an AAPD of 1.85% and MAPD of 10.1%.

The second algorithm, the proposed Model, uses a different form of the equation. The six parameter model was also tuned to match data from GPSA Figure 20-76 [2]. The resulting AAPD is 1.50%, and the MAPD is 7.14% compared to Figure 20-76.

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 consu...@jmcampbell.com.

How about accuracy vapor pressure prediction for TEG with small HC quantity (i.e. regenerated TEG on the TEG regenerator)? Hysys predict the vapor pressure almost equal to the operating pressure. Is it accurate enough compared to the actual condition?

TULSA, Okla., April 27, 2017 /PRNewswire-USNewswire/ -- GPSA announces the release of the 14th edition of its Engineering Data Book, a two-volume set with more than 1,000 pages of technical and design information pertaining to the midstream industry and its approved practices and procedures. The book has also been widely accepted among the petroleum refining, gas transmission and petrochemical industries.

First introduced in 1935, the Data Book assembles basic design information together with data and procedures that can be used by field and plant engineers to determine operating and design parameters. It is also intended as an aid to design engineers whom, in spite of increasing availability of computer routines and other sophisticated design methods, require a general reference work as a guide to accepted engineering practice for estimating, feasibility studies, preliminary design and for making on-site operating decisions.

Major changes from the previous 2012 edition have been made related to measurement, cooling towers, pumps and hydraulic turbines, compressors and expanders, and prime movers for mechanical drives. Other sections with changes include utility systems and maintenance, hydrocarbon treating, sulfur recovery, physical properties and thermodynamic properties.

The book is compiled by a joint editorial committee composed of technical specialists from both GPSA (suppliers) and the GPA Midstream Association (operators). This committee, known as the GPSA Editorial Review Board, continually reviews and revises the manual. Periodic revisions are issued to holders of record to keep the manual up to date with technology and industry practices.

"id":16,"name":"Methanol Injection Rate for Natural Gas Hydrate Prevention \u2013 be careful what simulators tell you!","user":"8","published":true,"content":"Hydrates in Natural Gas Processing FacilitiesThe formation of hydrates in natural gas processing facilities and pipelines is a critical issue as hydrates can plug equipment, instruments, and restrict or interrupt the flow in pipelines. Generally, hydrates will form when the temperature is below the hydrate formation temperature, normally with “free” water present, depending on the gas composition and pressure. How Can Hydrates Be Prevented?In general, hydrates can be prevented by:1. Maintaining the system temperature above the hydrate formation temperature by using a heater and\/or insulation.2. Dehydration of the gas to prevent the condensation of a free water phase.3. Injection of thermodynamic inhibitors to suppress the hydrate formation temperature in the free water phase.

Since heating or dehydration is often not practical or economically feasible, the injection of hydrate inhibitors is an effective method for preventing hydrate formation.Methanol (MeOH) is widely used as an inhibitor in natural gas pipelines, particularly in cold climate facilities (e.g., Canadian environments). In these difficult environments, methanol injection is the most economical solution for preventing hydrate formation and is often the only option.

Determination of Methanol Injection RateThe ChallengeThe determination of methanol injection rate can be a very challenging task for engineers, mainly because of methanol partitioning: the injected MeOH may partition into three phases: the aqueous phasethe vapor phasethe hydrocarbon phase. The amount of MeOH to be injected must be sufficient to suppress hydrate formation in the aqueous phase, and also to replace methanol “losses” to the equilibrium vapor and hydrocarbon liquid phases. In this article, we demonstrate how the GPSA manual and process simulators can be used to overcome these challenges and calculate the required methanol injection rate.  This information is crucial for safe pipeline operations.

Methods to Determine the Injection Rate of Methanol1. Manual Calculation per GPSA Engineering Data BookSteps:Determine the value of temperature suppression ‘d’ per design requirement.The aqueous phase is where hydrate inhibition “occurs”. The inhibitor concentration in the aqueous phase can be calculated by Hammerschmidt’s equation or the Neilsen-Bucklin equation. Thus, the required MeOH in the aqueous phase is determined.Once the required aqueous methanol concentration is fixed, it is necessary to establish the amount of methanol that is “lost” in the hydrocarbon liquid and gaseous hydrocarbon phases. By utilizing GPSA Fig 20-55 (GPSA 13th Edition SI), the MeOH losses in vapor phase can be determined.Methanol losses to the hydrocarbon liquid phase are more difficult to predict. Solubility is a strong function of both the water phase and hydrocarbon phase compositions. By utilizing GPSA Fig 20-56 (GPSA 13th Edition SI), the MeOH loss to the hydrocarbon phase can be determined.Total MeOH injection rate is the sum of the methanol in all three phases.Pros: GPSA Engineering Data Book is widely available and the methods contained in it are accepted by industry for calculating MeOH injection rates and are field-proven.Cons: Since the GPSA graphs (which are used to determine vapor and hydrocarbon losses) come from specific sources\/experimental data, they only apply to a certain range of gas conditions or compositions.

2. Process Simulators (Aspentech HYSYSTM)A Process Simulator like HYSYS provides more rigorous calculations in regards to hydrate formation temperature (by using the HYSYS hydrate formation utility) and will automatically calculate the inhibitor distribution in different phases (by flash calculation\/phase equilibrium).Process Ecology has worked closely with HYSYS on several methanol partitioning studies through the years.  It is crucial to choose an appropriate fluid property package (PP) to determine the methanol injection rate. Some commonly used property packages, like Peng-Robinson (PR) will largely overpredict MeOH requirement in the hydrocarbon phase.In May 2015, Aspentech released HYSYS v8.8 with the addition of the Cubic-Plus-Association (CPA) fluid property package. The new CPA PP can more accurately model methanol phase behaviors, especially in the modelling of liquid-liquid equilibria (LLE) including the prediction of the partitioning of methanol between water and hydrocarbons in the hydrocarbon phase.

Case studyProcess Ecology was requested to determine the inhibitor requirement for a specified fluid defined by a client.  The PFD of the system is shown below:

The results of the CPA package are promising, showing a marked improvement in methanol inhibitor predictions in particular when compared to alternative methods. For example, the amount of methanol required to suppress hydrate formation temperature in a specified fluid from 20 °C to 0 °C is as follows:

Using the CPA PP in HYSYS results in a MeOH injection rate that is much closer to the number calculated by GPSA, compared to the rate predicted by the Peng Robinson PP.

ConclusionsIn short, while process simulators like HYSYS bring significant benefits and convenience to operating and engineering companies, results must always be carefully evaluated and selection of the correct property package when performing calculations is essential.For methanol injection rate calculations in HYSYS, we believe that the Peng Robinson property package vastly overpredicts the amount of methanol partitioned, or “lost” into the hydrocarbon liquid phase. We have demonstrated that the new CPA property package gives a much better prediction of required MeOH rates for hydrate suppression.

ReferencesGas Processors Suppliers Association (GPSA) Engineering Data Book, 2012 SI unit,13th EditionThermodynamic Models for Industrial Applications: From Classical and Advanced Mixing Rules to Association Theories. 2010. Georgios M. Kontogeorgis, Georgios K. Folas.

Do you have questions or comments regarding this article? Click here to contact us.","category_id":3,"keywords":"methanol injection; natural gas processing; hydrate formation","published_date":"2015-06-02","created_at":"2016-10-21 19:59:03","updated_at":"2021-03-22 04:56:30","slug":"methanol-injection-rate-for-natural-gas-hydrate-prevention-be-careful-what-simulators-tell-you","downloads":1077,"description":"Manual calculation with the GPSA engineering data book and process simulators can be used to calculate the required methanol injection rate.","tagtitle":"Methanol Injection Rate for Natural Gas Hydrate Prevention","image":null,"category":"id":3,"name":"Natural gas processing","for":"Article","image":"\/img\/uploads\/3d3b1dd7136a4a530d219a40ea5033a414330d34.png","created_at":"2016-12-16 00:45:44","updated_at":"2017-04-05 09:04:34","published":true,"editable":false,"slug":"natural-gas-processing"

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