Matthias Bauer, TECON Engineering; Mario Köck, TPS;
Klaus Jörg and Chandrasekhar Ramakrishnan, TECON Engineering; and Andreas Scheed, OMV

Summary

The full-length paper describes the project evolution, from the first study to the implementable concept of energy production using the associated gas of two onshore facilities in Tunisia. Despite its complex composition, high carbon dioxide (CO2) content, high hydrogen sulfide (H2S) concentration, and the relatively low quantities of available flared gas, a technically and economically feasible solution was developed successfully.

Introduction

Thyna Petroleum Services (TPS) is a Tunisian joint-venture corporation of the Tunisian governmental oil and gas company, Entreprise Tunisienne d’Activités Pétrolières (ETAP), and the Austrian oil and gas affiliated group OMV AG based in Sfax. One of the future objectives of TPS is to avoid, or at least reduce, flaring of associated
gas contained in crude oil during oil production. A particular challenge is to discover a process that enables the use of the associated gas despite its untypical gas composition for valorization processes.
Use of the associated gas will also reduce greenhouse-gas emissions. Therefore, this project also could be considered as a Clean Development Mechanism (CDM) project (United Nations 2010).
CDM is an arrangement under the Kyoto Protocol that allows industrialized countries with an emission-reduction or emission-limitation commitment to invest in an emission-reduction project in developing countries as an alternative to more-expensive emission reductions in their own countries. Such projects can earn saleable certified-emission-reduction (CER) credits, each equivalent to 1 ton of CO2, which can be counted toward meeting the Kyoto targets.
Increasing energy prices over the last few years, as well as enhancements in the process area, make the use of associated gas more and more interesting. Furthermore, the pressure of environmental and political organizations to develop new alternatives to flaring is constantly rising.

Current Gas Flaring at TPS Stations

TPS currently operates three crude-oil-preconditioning plants. There are two onshore facilities, “Tank Battery” and “Guebiba Station” near Sfax, and one offshore facility, “Cercina Delta Platform,” close to Kerkennah Island, located approximately 30 km from Sfax. Associated gas, which accrues from the conditioning process, is currently flared at all three process facilities, without heat recovery.

Gaining Additional Energy From Unused Resources

The increasing contamination caused by polluting emissions, together with the associated consequences on human beings, animals, and nature, results in an obligation to seek new processes for the use of potential energy sources. It is an essential challenge to find an economically and technically feasible option that would commute the existing energy value within the associated gas (heating value) into usable energy.

Possibilities of Power Generation With Gas

In 2008, efforts to find a possibility to use the associated gas have increased. The Austrian engineering service provider TECON was commissioned to perform a feasibility study. In the “gas valorization” feasibility study of the two onshore facilities, the possible available power-generation processes were investigated. To simplify the selection process, a process evaluation flow sheet was developed, which can be seen in Fig. 1. The first step was to conduct a preselection of possible gas-use technologies on the basis of the amount of associated gas.

Preselection of Applicable Gas Use Technologies

Because of the relatively low amount of associated gas from both stations (Tank Battery, 1,200 Nm³/h; Guebiba, 600 Nm3/h), large conventional power plants fired with the associated gas did not come into consideration. Therefore, the research focused on the following technologies for a decentralized application: gas turbine, microturbine, and gas engine. All three technologies are well suited for in-situ power generation out of the existing energy source within the associated gas field and are robust enough to resist load variations.
Turbines and microturbines are based on the same principle. As the name itself indicates, a microturbine is a turbine with a lower performance level. Although there is no clear border between turbines and microturbines, a microturbine would typically correspond to performance levels lower than 500 kW.
Gas engines are available in a broad spectrum of power ranges, typically between 20 and 1,500 kW.

Direct Use of Crude-Oil Associated Gas

Preliminary investigations focused on power generation without any pretreatment of the gas. It quickly turned out that commercial gas engines cannot operate with the extremely high H2S content of the associated gas. Further investigations identified 500 ppm H2S as a maximum limit, which allows the use of the associated gas in a gas engine.
For untreated usage within turbines, the investigations were slightly more promising. Normally, turbines can handle H2S contents up to 500 to 2,000 ppm. After intensive research, just one manufacturer was found that offers a turbine that can handle associated gas with 5,500 ppm H2S, as at Tank Battery. However, the greatest disadvantage is that the use of a turbine at Guebiba Station is not feasible. Considering that the owner (TPS) prefers identical technologies on both sites, the implementation of a turbine was no longer an option without pretreatment.
The results of the investigations into possible use of microturbines without pretreatment were unsatisfactory. Without a predesulfurization process, only one kind of microturbine with a 65-kW power output could use the associated gas from the Guebiba Station (13,400 ppm H2S), as well as that of Tank Battery. But in order to deal with the whole flow rate there, approximately 10 of these units would need to be installed in Guebiba Station, and approximately 20 units in Tank Battery. Hence, this is not recommended because of the additional requirements of space, the extended pipework needed, the subsequent maintenance on the numerous and complex instrumentation and the resulting high investment costs. After pre-treatment, microturbines with a higher power spectrum would also be an alternative.
Because of the composition of the associated gas (Table 1), with respect to a very high H2S and CO2 content and relatively low CH4 content, preconditioning upstream of the energy-production plant is required. Because of the higher H2S content at the Guebiba Station, all subsequent research concentrated on this station because a feasible solution at Guebiba would also be applicable at Tank Battery.
After identification of the technical necessity of pretreatment, the next step was the selection of the best-fitting gas-conditioning process.

Requirements of Gas Conditioning

The challenge was therefore to identify a low-cost conditioning process, preferably implementable on both onshore stations. The main purpose of the conditioning treatment was to increase the lower heating value (LHV) by means of a reduction in the CO2 content, as well as a reduction in the H2S content at the same time.
With regard to the fuel requirements of most gas turbines and engines, no extra-fine desulfurization is necessary. Therefore, investigations concentrated on a maximum H2S concentration in the treated fuel gas of 500 ppm. Another requirement for the optimal gas-conditioning process is a reduction in higher hydrocarbons (C3+). This would lead to an increase in the methane number, which is also an important factor for gas engines.

Gas-Treatment Selection

Table 2 shows the technical decision matrix for the investigated gas-conditioning technologies. With regard to the previously described criteria, eight gas-treatment technologies were compared to identify a technical and economical optimized process.
The technical comparison shows that NaOH wash, anaerobic digestion, and activated carbon will need undeliverable amounts of necessary chemical ingredients. Therefore, they were eliminated from further consideration.
The Shell Paques process and iron oxide process technologies would be theoretically applicable, but not efficient enough for a subsequent energy-production plant. Both processes do not remove or reduce the CO2 and the C3+ content. The treated gas would be less corrosive because of the reduced H2S content, but the LHV would still be in a
very low range, so they were also no longer under consideration. Consequently, the membrane process and pressure-swing-adsorption (PSA) process turned out to be technically favorable technologies.
The final decision between these two technologies was dependent on the economics. Therefore, tenders for both were requested.
The evaluation of the tenders identified that the membrane technology presented both lower capital expenditures (CAPEX) and lower operational expenditures (OPEX) than the PSA technology.
Membrane processes are often used for pretreatment downstream of fine cleaning units. The chosen membrane process is able to reduce the H2S content to approximately 300 ppm, which is a value that can be handled by gas engines as well as by microturbines, so that further fine conditioning would not be required in the present case. This fact elevates membrane technology into a position as favorite.
After technical and economical evaluation, membrane technology was chosen as the most feasible technology to treat the associated gas and bring it into a usable condition.

Gas Conditioning by Means of Membrane Technology

In general, a membrane operates on the principle of selective permeation. Each gas component has a specific permeation rate. The components with higher permeation rates (such as CO2, H2, and H2S) will permeate faster through the membrane module than components with lower permeation rates (such as N2, C1, C2, and
heavier hydrocarbons).
Fig. 2 shows a block schema of a suitable membrane unit, where a compressed gas flow is divided into two different streams plus a recirculation flow by polar solubility selective membranes. This membrane system separates C3+ hydrocarbons as well as H2S and CO2 from the associated-gas stream.
Table 3 shows the increasing associated gas quality by comparing the main input parameters and the resulting output streams after the membrane unit.
A large fraction of the gas (referred to “off-gas” in Table 3) that contains the most corrosive components and fractions of the incombustible components is separated from the main stream and directed to the flare. Despite the incombustible fractions in this offgas stream, analysis has shown that this gas is combustible in a flare by adding a specific amount of air. Flaring is the safest and cheapest way of disposing of the highly toxic H2S. Resulting SO2 emissions would also be produced in the case of direct flaring of the entire associated gas, which means that this does not constitute an additional environmental concern.
For power generation, the fuel gas is of great interest (referred as “fuel-gas” in Table 3). In fact, this resulting fuel-gas stream is approximately one-third of the of the total flow rate. However, owing to the increase in the LHV, the overall energy content does not decrease proportionally to the volume. The relevant fractions with a
high energetic value, especially CH4, remain within the gas stream.
After being isolated from all contaminating components, this outlet gas stream, in contrast to the inlet gas stream, is usable with all investigated types of power-generation facilities.

Technical and Environmental Gas-Use Technology Comparison

Following the decision on the most applicable gas-conditioning process, the most beneficial gas-use process has to be identified. As initially mentioned, the technology selection was limited to the gas engine and microturbines because of the low amount of available associated gas. In principle, all preselected technologies
are operable with the cleaned gas from the membrane.
In environmental terms, by considering CO2 emissions, all technologies return the same values. Noise disturbances can be avoided by a containerized design in all cases, and regarding dispersion and radiation, no elementary differences were calculated.
While gas engines are usually in a spectrum of approximately 40% electrical efficiency, turbines offer between 30 and 35% electrical efficiency. For this reason, a higher electrical output can be assumed by the application of gas engines.
An essential technical aspect that also influences the economics is the necessary equipment required for the correct operation of the plant. Turbines and microturbines work with higher inlet pressures than gas engines. Both at Guebiba Station and at Tank Battery, the natural-gas pressure is very low and not sufficient to operate turbine technologies, which require an inlet pressure of approximately 10 bar. Therefore, a compressor to boost the gas is required. This fact would provide the gas engine with a very crucial advantage. But because
the membrane gas conditioning also requires an inlet pressure of 10 bar, a compressor is necessary in all cases. Regarding instrumentation and control systems, all technologies are at a similar technical level.
A further advantage to gas engines is that the staff of TPS already has experience with their operation. TPS uses gas engines at some offshore wells to operate the electrical submersible pumps to pump the crude oil to the treatment platform. In contrast, TPS does not currently operate turbines or microturbines.
Summing up all previous technical and environmental aspects, the application of gas-engine technology is preferable from a technical point of view.
Nevertheless, the gap between the technologies from the technical point of view is in a range that for a final decision, a detailed economical comparison is required.

Cost Comparison of Gas-Use Technologies

Quotes were requested for all required processes. To ensure a transparent comparability, the vendors were requested to breakdown their quotes into main-equipment cost (CAPEX) and yearly operational and maintenance costs (OPEX).
The economic evaluation was executed by a comparison of CAPEX plus seven times OPEX. Because the costs for transport (which are mainly influenced by the costs for the booster, instrumentation, and control system and connection to the local electricity supply) are in a similar range, these costs were not considered in this cost comparison.
An evaluation of the values (Table 4) pointed to the gas engines being favorable from an economic point of view. Together with the fact that gas engines offer a higher electrical-output efficiency, it was concluded that gas engines present the most beneficial technical gas-use solution.

Resulting Gas to Power Configuration

Fig. 3 shows the most beneficial technical solution developed to valorize the associated gas at the Guebiba Station and at Tank Battery. Because of the low associated-gas pressure, a prerequisite is to compress the almost atmospheric associated gas to the necessary operating pressure of the membrane unit. To avoid condensation problems in the compressors, it is necessary to cool the associated gas by an air cooler and to separate droplets out of the gas stream within a knockout drum. After the compressor, another air cooler is required to cool down the compressed gas again. The eventually condensing hydrocarbons get separated by another knockout drum before the gas stream enters the two-stage membrane unit, where the gas is divided into three resulting streams. The off-gas stream (No. 4) of the first stage gets directed to an existing flare unit. The off-gas of the second stage, which has a lower H2S and CO2 content than the off-gas of the first stage, gets recirculated. Because of the low pressure of this recirculating stream (No. 3), it is necessary to tie in upstream of the compressor. The resulting fuel gas (No. 5) with a high LHV and lower H2S and CO2 content gets mixed with air and is combusted in a gas engine. The planned configuration also has forseen the possibility to send the associated gas, as it was before the implementation of the valorization unit, directly to the flare in the case of maintenance or other reasons.

Recovered Electrical Energy

The amount of energy produced is calculated on the basis of the established gas volume flow multiplied by the fuel-gas density, its LHV, and a maximum efficiency of 45%. The energy demand of the power-generation facility itself (mostly required by the compressor)
shall be subtracted from the total output. In consideration of the points previously raised, a net current output of 0.71 MW at Guebiba Station and almost 1 MW at Tank Battery could be realized. A calculation of the net current output from both stations is shown in Tables 5 and 6.

Economic Analysis of Guebiba Station

For Guebiba Station, an economic analysis over 12 years was conducted. The investment and operational costs, including maintenance costs, were compared to the annual benefit of the produced electricity. Electricity prices were verified by the local electricity supplier.
The maintenance and operation costs were calculated with 0.010 €/ kWh. For operational and maintenance costs as well as for electricity prices, an annual increase of 5% was determined on the experience of the last few years. After 7 years, a major overhaul is necessary. In coordination with gas-engine vendors, it was determined that costs for a new gas engine should be included. For this reason, the benefit line bends down in Year 7 (see Fig. 4, which shows the cost/benefit ratio on the basis of the parameters collected in Table 7).

The economic analysis shows that from the second year, a continuous cash flow can be calculated. Taking all previously mentioned values into account, a payback period of less than 5 years was calculated.
Even with the necessary major overhaul, the cumulative cost benefit ratio stays in a positive balance.
the plant availability is 95%, the energy output of approximately 6,300 MWh/a at the Guebiba gas-use plant could cover a large fraction of the total Guebiba Station energy demand of 8,880 MWh/a. Thereby, the energy supply costs at this station could be reduced to approximately 30%.

The influence of the CDM certificate has to be highlighted. At the TPS plants, there will not be a reduction in CO2 because the gas will just be burned in a gas engine instead of by useless burning in a flare.
But overall (consumer plus supplier), there is a reduction in CO2 pollution. Because of the self-production of electrical energy with the gas engine, it is not necessary to purchase as much electricity from a supplier who will thus emit less CO2. The CDM Program of the United Nations now offers the company that enacts these reductions certificates per ton of CO2 reduction. At a selling price of 13.25 € [average price for CER in Austria in 2009 according to Energy Exchange Austria (2009)] per certificate (1 certificate=1 ton CO2), an annual additional benefit of approximately 51.000 € is anticipated from the sale of the certificates.
To point out the positive economic effect of the CO2 certificate sale, Fig. 5 explicitly shows the economic benefit of the certificate trading. As mentioned, the power output at Tank Battery is approximately 30% higher than the output of Guebiba Station as a result of the higher amount of associated gas. At the same time, the energy demand of Tank Battery at 2,671 MWh/a is significantly lower than at Guebiba Station. For this reason, a significant surplus of electrical energy can be produced at the Tank Battery. By law, the local electricity supplier is obligated to buy this.

Conclusions

After extensive studies, technically and economically feasible powergeneration concepts for the use of associated gas to produce electric power were established. The unusable incoming associated gas composition with a very high CO2 and H2S content at the onshore facilities was a process and economic issue. An additional challenge was to find a common solution for both facilities, which was required by the operator (TPS) with special regard to operation, personnel training, and maintenance and capital expenditure. Conditioning by means of a membrane technology and electrical power generation by means of a gas engine can be applied at both onshore sites.
The concept presented enables a nearly self-sustaining operation of its two main oil-processing facilities, and beyond this the production of a significant surplus of electric energy at Tank Battery that can be sold to the local electricity supplier. A large portion of the associated gas, which was neglected as a potential power source in the past, can now be applied in the gas-use process.
By using the self-produced electricity and selling the surplus to the local electricity supplier, a payback time of less than 5 years was calculated for the installation of both onshore plants.
In addition to this economic aspect, the positive influence of the project to the environment because of a reduction in CO2 emissions should also highlighted. The technical concept set a milestone. The next step is the actual implementation of the project to approach TPS’s ambitious target—from liability to value.

References

Energy Exchange Austria (EXAA). 2009. Annual Report 2009
United Nations. 2010. Framework Convention on Climate Change: Clean Development Mechanism (CDM)
Matthias Bauer is project manager of multiple projects in oil and gas industry in Austria, Tunisia, Yemen, and Pakistan with TECON Engineering, where he’s been employed since February 2007. Within the paper related project, he was the project manager of TPS’ engineering partner TECON. He holds an MSc degree in mechanical engineering from the University of Cooperative Education.
Mario Köck works for OMV Yemen as the operations and maintenance manager. He is responsible for all onshore oil production activities within OMV Yemen’s Block S2, located in the desert of Yemen. He joined OMV as a production engineer in 2002 and was assigned to OMV Tunisia as development manager in 2007 where he was responsible for operations and projects in OMV Tunisia’s joint venture “Thyna Petroleum Services.”He holds a ME degree in petroleum engineering from the Mining University of Leoben.
Klaus Jörg is head of process engineering where he is responsible for all process related activities at the 3 TECON offices in Austria and Romania. Within the paper related project, he was the process lead engineer. He holds a MSc degree in process engineering and a PhD degree in mechanical engineering from the Technical University Vienna, Austria, and a MBA degree from the University of Klagenfurt.
Chandrasekhar Ramakrishnan joined TECON Engineering GmbH in After heading the process engineering department for the first 4 years, he lead the business development department for the next 4 years and was recently promoted to director of refining and upstream. He was involved in the flare gas recovery projects as a senior engineer,
closely cooperating with the project team in developing the suggested engineering solutions. He holds an MSc and PhD degree in chemical engineering from the Technical University of Vienna.

مطالعه و بررسی روشهای بازیافت و كاهش گازهای ارسالی به مشعل

اصغر خطیبی لیلا یوسفی

چکیده

پدیده گرم شدن زمین یكی از مشكلات عمده ای می باشد، كه جهان امروز با آن مواجه است. این پدیده در كوتاه مدت باعث آلودگی محیط زیست و در دراز مدت سبب تغییرات جغرافیایی و آب و هوایی می شود. از جمله عوامل این پدیده مخرب انتشار گازهای حاصل از احتراق در مشعلهای واحدهای پالایشگاهی و پتروشیمی است. علاوه بر اثرات مخرب زیست محیطی ناشی از انتشار این گازها اتلاف انرژی نیز از پیامدهای نامطلوب آن می باشد. كشور ایران در زمینه انتشار این آلایندگی نقش بسزایی در جهان و خاور میانه دارد. بنابراین مجموع این عوامل مدیران صنعت نفت و گاز را برآن داشته كه در جستجوی روشهای حذف و یا كاهش این آلایندگی در جهت حفظ محیط زیست و صرفه جویی اقتصادی با رویكرد كاهش مصرف انرژی و حتی تولید آن باشند. در این بین تعداد بسیار زیادی از محققان ترغیب به مطالعه و بررسی راهكارهایی برای حذف و یا كاهش این آلایندگی ها شدند. در این تحقیق سعی شده است عوامل منجر به این آلایندگی ها شناسایی و معرفی شود و راهكارهایی برای رفع این عوامل با توجه به كاهش مصرف سوخت و اتلاف انرژی و در مواردی تولید انرژی بر پایه حذف و عدم انتشار گازهای محترق در مشعلها ارائه گردد.

1-مقدمه

سالانه بیش از 150 میلیارد مترمكعب گاز طبیعی در مشعلها می سوزد. این رقم معادل %4 سالانه كل گاز تولیدی جهان است وعلاوه بر اتلاف مقدار بسیار زیاد انرژی، 207 میلیون تن دی اكسید كربن نیز در جو منتشر می شود. این میزان دی اكسید كربن تاثیر بسزایی در پدیده گلخانه ای و همچنین کاهش pH باران های اسیدی دارد.از طرف دیگر سالانه مبلغ قابل توجهی صرف نگهداری از مشعل و سیستم مربوط به آن میشود.(1)
افزایش آلودگی محیط زیست بر اثر انتشار و تولید گازهای ناشی از احتراق مشعلهای موجود در صنایع نفت، گاز و پتروشیمی از یكسو و افزایش نیاز به مصرف انرژی به دلیل ازدیاد روز افزون جمعیت و پیشرفت تكنولوژی و هزینه های بالای تولید آن از سوی دیگر سبب شده كه نظر بسیاری از مدیران و متعاقبا محققین به سمت روشهای مهار و كاهش آلایندگی ناشی از عملكرد مشعلها معطوف شود. كشور ایران نیز به دلیل دارا بودن سهم بالا در منابع نفت و گاز دنیا و صنعت و تكنولوژی استحصال و پالایش آن تاثیر بسیار زیادی بر پدیده افزایش دمای زمین، تخریب اتمسفر و آلودگی محیط زیست دارد. طبق آمار منتشره از مراجع ذیصلاح ایران رتبه سوم در جهان و رتبه اول در خاورمیانه به لحاظ تخلیه یا سوزاندن گازهای قابل بازیافت در مشعلها را داراست. شكل 1 سهم كشورهای مختلف را در تولید گازمشعل نشان می دهد.(2)

از این رو مطالعات و تحقیقات متعددی برای رفع این مشكل در سطح صنعت و دانشگاه انجام شده است. كه بطور مختصر به برخی از این موارد اشاره می شود. رحیم پور و جوكار در سال 2011 میلادی اقدام به انتشار مقاله ای تحت عنوان امكان سنجی تبدیل گازهای خروجی از مشعلهای پالایشگاه گاز فراشبند به انرژی نموده اند. ایشان به سه روش تولید گاز مایع، برق و نیز استفاده این گازها به منظور تزریق در خطوط لوله پالایشگاهها اشاره كرده و نتایج زیست محیطی و اقتصادی آنها را شبیه سازی نموده اند.(3)
رحیم پور وهمكاران در سال 2011 تحقیقاتی بر روی تبدیل گاز خروجی در پالایشگاهها به هیدروکربنها ی مایع با استفاده از تکنولوژی غشاء تراوای هیدروژنی ارائه نموده اند.درضمن ایشان نتایج حاصل از این تحقیق را در محیط زیست مانند کاهش اثرات گلخانه ای تحلیل نموده و سود تقریبی حاصل از تبدیل گازهای ارسالی مشعل به ترکیبات با ارزشی مثل اتیلن، پروپیلن و بوتان را برآورد نموده اند.
در تحقیقی دیگر که توسط قاسمیه و همکاران انجام شده است، جمع آوری و تزریق گازهای قابل بازیافت را به مخازن نفتی ایران به عنوان راهکاری مفید که هم باعث صرفه جویی اقتصادی از لحاظ درآمدهای حاصل از ازدیاد برداشت مخازن نفتی با افزایش فشار ناشی از تزریق گاز میشود و نیز سبب کاهش میزان آلودگی ناشی از انتشار یا سوزاندن گازهای مزبور خواهد شد، معرفی کردند.
در این مقاله همراه ذکر دلایل منجر به افزایش آلودگی ناشی از انتشار و یا احتراق گازها در مشعلها راهکارهایی برای رفع یا کاهش آنها ارائه می شود.

2-روشهای كنترل و مهار آلایندگی و دود در مشعل

برای جلوگیری از انتشار آلایندها بواسطه وجود و عملكرد مشعل باید هدف و معیار كنترل آن مشخص شود. گاهی با توجه به مشكلات و آلودگی های محیط زیستی كه جوامع صنعتی امروزه با آنها روبرو هستند، تنها به جنبه های محیط زیستی آلاینده ها دقت می شود ولی در چشم اندازی وسیع تر علاوه بر مسایل زیست محیطی، صرفه جویی های اقتصادی كه از طریق استفاده و كاربرد گازهای ارسالی مشعل به عنوان انرژی قابل استفاده برای موارد مختلف نیز میتواند مورد توجه قرار گیرد. معیار كنترل آلایندگی در مشعل می تواند شامل ساختار مشعل وملحقات آن و كنترل گازهای ارسالی به مشعل با روشهای حذف یا كاهش آنها باشد.

1-2- جلوگیری از ارسال گازها به مشعل

یكی از دلایل وجود مشعل سوزاندن گازهای خروجی از شیرهای اطمینان می باشد. شیرهای اطمینان معمولا به منظور حفظ ایمنی سسیستم در مواقعی كه فشار سیستم از فشار بیشینه مجاز طراحی شده افزایش می یابد واحتمال خطر انفجار یا تركیدگی در سیستم وجود دارد، طراحی و تعبیه می شود كه در اینگونه مواقع این نوع شیرها باز شده و جریان گاز از آن به محیط یا به خط لوله متصل به مشعل برای سوختن ارسال می شود. كه كمترین پیامد مخرب آن در هر دو حالت افزایش انتشار آلاینده ها در محیط زیست می باشد. پس اگر تدابیری اندیشیده شود كه از افزایش فشار سیستم به بیش از فشار بیشینه طراحی ممانعت به عمل آید و نیاز به طراحی و نصب هیچ شیر اطمینانی نباشد، جریان گازی نیز به محیط یا خط لوله اصلی مشعل منتقل نخواهد شد. این عمل از طریق استفاده از تكنولوژی سیستم یكپارچه حفاظتی بالا (HIPPS) براساس استانداردهای بین المللی IEC61508, 61511 امكان پذیر می باشد.مطابق شكل 2 این سیتم نوعی سیستم ابزار دقیق است كه شامل دو عدد شیر و یك آشكار ساز فشار می باشد.

در این سیستم به محض رسیدن فشار سیستم به میزان بیشینه طراحی شده، شیرها عمل نموده و در كمتر از چند ثانیه بسته می شود تا مسیر عبور جریان به سیستم كه باعث افزایش فشا ر ازحد مجاز می شود، بسته شود . د ر این نوع طراح ی مضاف بر اینكه نیازی به شیر اطمینان نیست، به دلیل عدم انتقال جریان با فشار بسیار بالا به مرحله بعدی سیستم احتیاج به سایز بالای تجهیزات و خطوط لوله انتقالی نخواهد داشت، كه این امر موجب كاهش هزینه سرمایه گذاری می شود. همچنین تجهیزات این سیستم فضای كوچكی از واحد صنعتی را اشغال می كنند. از مشكلات این سیستم كه شاید بتوان به عنوان عیب از آن یاد نمود، پیچیدگی سیستم می باشد كه نیاز به طراحی بخشهای متفاوت دارد.

2-2- بازیافت گازهای ارسالی مشعل

با استفاده از سیستم باز یافت گازهای ارسالی به مشعل می توان علاوه بر كاهش آلودگی و اتلاف انرژی، از گاز های ارسالی به مشعل انرژی تولید كرده ویا آنرا به شبكه گاز مصرفی تزریق نمود. با توجه به تركیب و حجم گازهای ارسالی به مشعل و موقعیت مكانی واحد صنعتی روشها و فناوریهای متعددی برای بازیافت این گازها آزمایش و ارائه شده است. برخی از این فناوریها عبارتند از:

• جمع آوری و تزریق به مخازن نفتی
• جمع آوری و تزریق به مخازن زیر زمینی
• جمع آوری و تزریق به تاسیسات جمع آوری گاز طبیعی و انتقال به شبكه گاز سراسری
• تولید برق
• تولید آب گرم و یا بخار با استفاده از گرمای سوختن گاز
• استفاده از فرایند GTL
• استفاده درپیلهای سوختی
• استفاده در شیرین سازی آب دریا
• استفاده از سیستم mini-LNG
• سیستم اژكتور
• سیستم كمپرسور با حلقه مایع

به ترتیب توضیحی مختصر برای هر یك از روشهای مزبور ارائه می شود:

1-2-2- جمع آوری و تزریق به مخازن نفتی

از جمله گازهای ارسالی به مشعل گازهای همراه در میادین نفتی است. تزریق گاز همراه به مخازن نفتی به منظور ازدیاد برداشت همواره یكی از روشهای جلوگیری از سوزاندن این گازها می باشد. در ایران علاوه بر برداشت اولیه كه تولید طبیعی از مخزن است، روشهای برداشت ثانویه تزریق گاز یا آب در اكثر مخازن در حال برنامه ریزی و اجرا می باشد كه باعث افزایش برداشت حدود % 5 از مخازن می گردد. در بازیافت ثانویه هدف این است كه با افزایش انرژی طبیعی مخزن از طریق تزریق گاز یا تزریق آب برای حفظ فشار و یا افزایش فشار مخزن و یا به كمك بهبود روشهای تولید از قبیل نصب تلمبه های درون چاهی، حفاری های افقی، حفاری های بین چاهی فرازآوری با گاز عمل افزایش برداشت از مخازن انجام شود. درحال حاضر تزریق گاز به میادین بی بی حكیمیه، پازنان، پارسی، رامشیر، كرنج، كوپال، گچساران، رگ سفید، مارون و هفتكل صورت می پذیرد.(6)

2-2-2- جمع آوری و تزریق به مخازن زیر زمینی

چنانچه حجم گازهای ارسالی به مشعل كم باشد یا ابزار و فناوریهای لازم برای استحصال انرژی آن در دسترس نباشد و یا اینكه هزینه های سرمایه گذاری برای بازیافت این گازها بالا باشد، برای جلوگیری از انتشار آلودگی ناشی از احتراق این گازها در مشعل می توانند بجای انتقال به مشعل در مخازن خالی زیر زمینی ذخیره شوند تا به محض فراهم شدن شرایط مناسب برای كاربردهای بهینه صنعتی استفاده شوند.(1)

3-2-2- جمع آوری و تزریق به تاسیسات جمع آوری گاز طبیعی و انتقال به شبکه گاز سراسری

استفاده از این فناوری در كنار طراحی مشعل از دیر باز متداول بوده است. به كمك این روش 20 % از گاز های تخلیه اضطراری و 90 % گاز در حالت عادی به فرآیند باز می گردد. با توجه به واحدهای حذف آلاینده در پالایشگاههای گازی، این روش می تواند با بازده بالایی قابل استفاده قرار گیرد.(1و9)

4-2-2- تولید برق

با استفاده از تكنولوژی مولدهای الكتریسیته و سیستم بازیابی گازهای ارسالی مشعل می توان از گازهای فلرینگ پالایشگاه استفاده نموده و از این طریق انرژی الكتریكی تولید نمود. با این روش نه تنها الگوی مصرف انرژی بهینه می گردد بلكه در بخش تولید برق نیز، اصلاح الگوی تولید صورت می گیرد . همچنین با ایجاد این طرح از میزان انتشار گازهای گلخانه ای مانند دی اكسیدكربن كاسته می شود. برای تولید برق با استفاده از گازهای ارسالی به مشعل روشها و فناوریهای متفاوتی وجود دارد. انتخاب هریك از این فناوریها بستگی به میزان و اجزاء تركیب گاز ارسالی به مشعل دارد. در این میان می توان به فناوری تولید برق از طریق روشهای ذیل اشاره نمود:
موتور گازسوز
توربو ژنراتور
میكرو توربین
موتور گازسوز

5-2-2- استفاده در فرآیند GTL

تبدیل گاز به مایع (GTL) با استفاده از گرمای حاصل از سوختن گاز مشعل یکی دیگر از روشهای مناسب در بازیافت گاز مشعل می باشد.باشد. این فناوری به نظر می رسد تفاوت چندانی با روش تبدیل گاز مشعل به برق نداشته باشد. و در عمل از سوختن گاز انرژی مورد نظر برای تولید GTL یا برق ایجاد می گردد. اما استفاده از میكرو راكتور و درواقع بالابردن بازده سیستم باعث شده این فناوری در بعضی شرایط جذابیت و توجیه بیشتری نسبت به تولید برق داشته باشد. شکل 3 برش میکرو راکتور یا درواقع میكرو مبدل و شكل 4، نیز فرآیندتولید GTL را نشان میدهد.همانگونه كه مشاهده می شود در این فرآیند از گاز مشعل برای تولید گرما در اصلاح کننده بخار (Steam Reforming) استفاده می شود. واضح است در صورت عدم استفاده از سیستم احتراق كنترل شده با انتشار كم گازهای آلاینده، در عمل فقط انرژی گاز مشعل بازیافت شده است وآلایندگی گاز مشعل كماكان برقرار می باشد. لذا در این فرآیند حذف گازهای آلاینده با استفاده از روش های سوختن و احتراق پیشرفته و كنترل شده، كمك مضاعفی به كاهش گازهای آلاینده می كند. استفاده از میكروكانال، باعث افزایش بازده مبدل حرارتی و در نتیجه كاهش مصرف انرژی و همچنین بالارفتن سرعت فرآیند می شود.(1و16و10و11)

6-2-2- استفاده درپیلهای سوختی

پیل سوختی اساساً وسیله ای است كه سوخت (مانند هیدروژن ، متانول، گاز طبیعی، بنزین و…) و اكسیدان (مانند هوا و اكسیژن) را به برق، آب و حرارت تبدیل می كند. به عبارت دیگر پیل سوختی شبیه یك باتری بوده ولی بر خلاف باتری نیاز به انبارش (شارژ) ندارد. تا زمانی كه سوخت و هوای مورد نیاز پیل تأمین شود، سیستم كار خواهد كرد. پیل های سوختی می توانند سوخت های حاوی هیدروژن مانند متانول، اتانول، گاز طبیعی، و حتی بنزین و گازوئیل را مورد استفاده قرار دهند. گاز هیدروژن به دلیل تمایل واكنش دهندگی بالا به همراه چگالی انرژی بالا به عنوان سوخت ایده آل در پیل سوختی مورد استفاده قرار می گیرد. هیدروژن را می توان از تبدیل هیدروكربن ها از طریق واكنش كاتالیستی، تولید و به صورتهای گوناگون ذخیره سازی كرد. بطوركلی در سوخت های هیدروكربوری، هیدروژن توسط یك دستگاه اصلاحگر سوخت (Fuel Reformer)، از آنها جدا شده و بكار گرفته می شود. پیل های سوختی در كاهش آلودگی محیط زیست نقش بسزائی داشته و بخاطر عدم بكارگیری قطعات مكانیكی زیاد، ایجاد آلودگی صوتی نیز نمی نماید. علاوه بر آن سیستم پیل سوختی از كارائی نسبتاً بالائی نسبت به موتورهای احتراق درونسوز برخوردار است. هیدروژن الكترون خودرا در آند از دست داده و بصورت پروتون از طریق الكترولیت به سمت كاتد حركت می كند. الكترون نیز از طریق مدار خارجی به سوی كاتد هدایت می شود. اكسیژن با دریافت الكترون و پروتون به آب تبدیل می شود. حركت الكترون از آند به كاتد جریان برق را به وجود می آورد كه قابل استفاده در وسایل برقی است. آب حاصل در كاتد می تواند مورد استفاده مجدد قرار گیرد. با توجه به اینكه گازهای ارسالی به مشعل در بیشتر موارد حاوی مقدار زیادی تركیبات گازی هیدرو كربنی است، از طریق بازیافت هیدروژن موجود دراین تركیبات و ارسال آن به آند خوراك اولیه پیل سوختی تامین و بدین ترتیب از گازهای ارسالی برای احتراق به مشعل برق، آب و حرارت تولید می شود، شكل 5 شمایی از یك پیل سوختی كه شامل دستگاه اصلاحگر به منظور بازیافت گاز هیدروژن از جریان گازی هیدروكربنی می باشد را نشان می دهد. (1و12و13)

7-2-2- استفاده در شیرین سازی آب دریا

پیش از اینكه به كاربرد و استفاده گازهای ارسالی به مشعل در شیرین سازی آب دریا پرداخته شود، فرآیند مورد نظر با استفاده از روش تقطیر موثر چندگانه (MED) تشریح میشود. مطابق شكل 6 این فرآیند شامل چند مرحله می باشد كه در هرمرحله آب دریا برروی لوله های مارپیچ حاوی بخار داغ پاشیده می شود. بر اثر تبادل حرارتی بین بخار داغ و آب دریا، بخار جاری در لوله ها مایع شده و از انتهای ظرف وارد مسیر آب تقطیر شده و یا نمكزدایی شده می شود. بخشی از آب دریا تبخیر و مابقی نسبت به نمك محلول تغلیظ می شود. آب نمك تغلیظ شده از انتهای ظرف تخلیه می گردد. بخش تبخیر شده كه به مراتب دما و فشار كمتری نسبت به بخار موجود در لوله دارد به سمت بالای ظرف منتقل و سپس وارد لوله های مارپیچ مرحله بعدی می شود و فرآیند مرحله اول در این مرحله نیز تكرار می شود با این تفاوت كه در هرمرحله تقطیر تحت دما وفشار كمتری انجام می شود. بخار حاصل از قسمت نهایی این سیستم برای فشارافزایی وارد كمپرسور بخار حرارتی (TVC) شده و بطورمجدد چرخه تولید آب نمكزدایی شده از آب دریا ادامه می یابد.

از آنجائیكه برای تولید بخار در مرحله نخست احتیاج به یك بویلر با جریانی از سوخت كم فشار می باشد، گازهای ارسالی به مشعل می تواند به عنوان سوخت بویلر استفاده شود. گرمای حاصل از احتراق این گازها انرژی لازم برای تبخیر آب و تولید بخار ورودی به كمپرسورهای بخارحرارتی را تامین خواهد نمود.(14و15)

8-2-2- استفاده از سیستم mini- LNG

یكی از بهترین پیشنهادات به منظور بازیافت گازفلر، استفاده از سیستم mini -LNG میباشد. در این سیستم گازمشعل بعد از افت فشار به درون مخازن ذخیره هدایت می شود. در این مرحله پس از حذف گا زهای همراه آلاینده، با استفاده از سیستم های كوچك پالایش و مایع سازی گاز LNG، گاز مشعل آماده فروش بوده و با استفاده از کامیون یا کشتی به بازار مصرف حمل میگردد.(1)

9-2-2- سیستم اژکتور

در برخی از صنایع احتیاج به جریان گاز با فشار متوسط می باشد، برای دستیابی به این جریان می توان از یك اژكتور مطابق شكل 7 استفاده نمود. اژكتور دارای دو جریان ورودی می باشد: جریان گاز با فشار بالا بعنوان محرك 14 كه بطور مستقیم وارد بخش نازل اژكتور می شود و جریان با فشار پایین كه در راستای عمود بر جریان محرك وارد اژكتور می گردد. پس از ورود دو جریان با فشارهای بالا و پایین باهم مخلوط شده و جریان گاز خروجی با فشار متوسط ایجاد می شود.

مطابق شكل 8 از گازهای ارسالی به مشعل می توان به عنوان جریان گاز با فشار پایین استفاده نمود (16)

10-2-2- سیستم كمپرسور با حلقه مایع

مطابق شكل 9و 10 یكی دیگر از روشهای بازیافت گازهای ارسالی به مشعل استفاده این جریان گازی در كمپرسورهای با جریان مایع می باشد.

كمپرسور سیستمی است برای افزایش فشار گاز، كه همراه با افزایش دما نیز می باشد. بطوریكه در بیشتر موارد ناگزیر از خنك كننده ها برای كاهش دمای گاز استفاده می شود. كمپرسورهای با جریان مایع این قابلیت را دارا هستند كه همراه افزایش فشار گاز دمای آن نیز بر اثر جریان مایع پایین نگه داشته می شود و نیازی به سیتمهای خنك كننده اضافی نخواهد بود. حال این جریان گاز می تواند گازهای ارسالی به مشعل باشد و اگر این گازها دارای تركیبات گوگرد (H₂S) بوده و به اصطلاح گاز ترش باشد، از جریان مایع با تركیب آمین در كمپرسور استفاده می شود تا علاوه بر پایین نگاه داشتن دمای گاز، ترشی و تركیبات گوگردی آن نیز توسط جریان مایع آمین زدوده شود.(5و17و18)

3- نتیجه گیری

با توجه به تاثیر آلایندگی گازهای دودكش مشعل براثراحتراق گازهای ارسالی به آن، به منظور كاهش آلایندگی و انتشار آن در محیط زیست در مرحله نخست باید عامل آلاینده حذف شود. ازآنجاییكه عامل آلایندگی، گازهای ارسالی به مشعل می باشد، روشهای جلوگیری از ارسال این گازها به مشعل و یا كاهش حجم ارسالی این گازها در اولویت قراردارند. كاربرد سیستم یكپارچه حفاظتی هرچند در نگاه نخست پیچیده و هزینه ساز می باشد اما با توجه به نتایج مطلوب حاصل از استفاده آن در محیط زیست و جلوگیری از اتلاف انرژی در دراز مدت مقرون به صرفه و اقتصادی خواهد بود. در مرحله دوم می توان از گازهای ارسالی به مشعل در موارد كاربردی صنعتی و حتی تولید انرژی با توجه به میزان و تركیبات آن استفاده نمود. در این مرحله روش منتخب علاوه بر میزان و تركیب گازهای ارسالی مشعل، به نوع واحد و موقعیت جغرافیایی آن نیز وابسته خواهد بود، عواملی كه علاوه بر امكان سنجی صنعتی و عملیاتی بر روی امكان سنجی اقتصادی روش بازیافت گازهای ارسالی به مشعل به عنوان روش منتخب تاثیر خواهد گذاشت. بنابر این با یك مطالعه اولیه در باره واحد صنعتی واجد مشعلهای آلاینده و تركیب و میزان گازهای ارسالی به مشعل و موقعیت جغرافیایی و استراتژیكی واحد مورد مطالعه می توان از یك یا چند روش كه در بخشهای مختلف این مقاله ارائه شده است بعنوان روش كاهش آلایندگی مشعل و یا حتی بازیافت انرژی ناشی از احتراق این گازها در مشعل استفاده و مطالعات امكان پذیری صورت داد.
جلوگیری، كاهش وبازیافت گاز های ارسالی به مشعل را می توان در قالب مقوله مدیریت پسماند بررسی و مطالعه نمود. در این راستا به علاقمندان و پژوهش گران توصیه میشود كه روش معروف و معتبری را كه به اختصار در ذیل معرفی شده برای بررسی و پژوهش های عمیقتر ، به كار گیرند.
كاهش: جلوگیری یا كاهش گازهای ارسالی به مشعل از طریق حذف، كاهش یا اصلاح روشهای عملیاتی.
استفاده مجدد: استفاده از مواد یا محصولاتی كه به شكل موجود قابل استفاده و كاربرد هستند.
بازیافت: تبدیل گازهای ارسالی به مشعل به مواد قابل استفاده یا تولید انرژی از این گازها
تصفیه: تخریب، سم زدایی و خنثی سازی مواد باقیمانده
دفع مسئولانه: استفاده از روشهای نسبی دفع گاز های ارسالی به مشعل (مثل تزریق به مخزن) كه اثر تخریبی بر محیط ندارند.

فهرست مراجع

[1] مهندس محسن فراكش، “ثروتی كه می سوزد” نشریه علمی، آموزشی و پژوهشی صنعت نفت، گاز و پتروشیمی- سفیر امید-سال اول شماره 4-صفحات 42-49
[2] “نفت و توسعه”، روابط عمومی وزارت نفت، 1382

[3] Rahimpour and Jokar,” Feasibility of flare gas reformation to practical energy in
Farashband gas refinery: No gas flaring” J. hazard mater. 2012
[4] Rahimpour and etal.,”Conversion of refinery natural purge gases to liquid hydrocarbon
loop with hydrogen –perm selective membranes: an alternative flaring”, J. natural gas science
and engineering. Volume 3, Issue 3, July 2011, Pages 461–475

[5]چاوش باشی و همكاران، “مطالعه امكان سنجی سیستم بازیابی گازهای ارسالی به فلر پتروشیمی تبریز و كاهش عملیات فلرینگ تحت مكانیزم CDM شرکت ملی صنایع پتروشیمی – شرکت سهامی پتروشیمی تبریز
[6] قاسمیه و همكاران، “بررسی روشهای كاهش سوزاندن گازهای قابل بازیافت در ایران”شركت مهندسین مشاور موننكو ایران

[۷] Mokveld Valves B.V.
[۸] Dr. Angela E. Summers,”Using Instrumented Systems For Overpressure Protection”, PESIS-TECH Solutions, LLC, Houston, TX Prepared for Presentation at the 34th Annual Loss Prevention Symposium, March 6-8, 2000 Overpressure Protection Alternative Session, Published in part in InTech, January 2000 Published in Chemical Engineering Progress, November 2000 Recipient of Bill Doyle Award for Best Paper Loss Prevention Symposium 2000
[۹] M.R. Rahimpoura, Z. Jamshidnejad, S.M. Jokar, G. Karimi, A. Ghorbani,”A comparative study of three different methods for flare gas Asalooye Gas Refinery”, Journal of Natural Gas Science and Engineering Volume 4, January 2012, Pages 17–28

[10] بهتاش كرمی و اسدالله ملك زاده، “بازیافت گازهای فلر با تكنولوژی GTL”، چهاردهمین کنگره ملی مهندسی شیمی ایران، تهران، دانشگاه شریف 1391

[۱۱] M.R. Rahimpour, A. Ghorbani, A. Asiaee, A. Shariati,” Conversion of refinery natural purge gases to liquid hydrocarbons loop with hydrogen-permselective membranes: An alternative flaring”, Journal of Natural Gas Science and Engineering Volume 3, Issue 3, July 2011, Pages 461–475

[12] اسماعیل ساعی ور ایرانی زاد “هیدروژن، پیل های سوختی و محیط زیست” دانشگاه تربیت مدرس و سازمان انرژی اتمی ایران و عضو كمیته فنی تكنولوژیهای انرژی.
[13] كمیته راهبری پیل سوختی

[۱٤] Multiple Effect Distillation Process, Veolia Water Solutions & Technologies, SIDEM, ۲۰۱۳
[۱٥] Multi Effect Distillation, IDE Technologies, 2011
[۱٦] Transvac Systems, Trasvac Ejector Technology, Trasvac CO.
[۱۷] Flare Gas Recovery Systems, NASH, A Gardner Denver Product.
[۱۸] Garo, Design and Manufacture Liquid Ring Compressor Systems.

Assessment of Organic Rankine Cycle for Electricity Production and Possible Coupling with Absorption Chiller

Abstract: Every year, flare gas is responsible for more than 350 million tons of CO2 emissions. Aside from thermal and environmental pollution impacts, flare gas contributes to global warming and enormous economic losses. Thus, waste heat recovery due to flaring gas can be explored through Organic Rankine Cycle ORC systems for electricity production. In this context, the assessment of a toluene ORC system is proposed for a potential application in an Algerian petrochemical unit.
The study focuses mainly on highlighting the potential and thermodynamic performances of the ORC application to produce electricity and potential cooling thanks to coupling an absorption chiller by recovering heat due to flaring gas. Such a solution can easily be implemented as an energy efficiency key solution. The ORC electrical production can meet the increasing demand of natural gas initially intended to be provided to a gas power plant and assures the major part of the Algerian electrical production.

1.Introduction
One of the major environmental problems related to the gas and oil industry is the unwanted natural gas released to the atmosphere by flaring [1]. The increased flaring gas process is caused by the increased demand of oil and gas production in addition to the pressure relief requirement in abnormal conditions [2] for safety purposes at refinery facilities. It should be considered that flaring enormous quantities of natural gas is an economic capital waste and is a major source of the reported important quantities of emitted gas components, such as carbon dioxide, methane, sulfur, NOx, volatile organic compounds (VOCs), and black carbon [3]. Statistical reports provided an amount of 400 million tons of CO2 emitted from about 150 billion cubic meters per year flared gas all around the world [4,5]. These emissions are dominated by the upstream petroleum sector [6]. Therefore, it is highly required to reduce the flared gas by improving the actual flaring gas techniques and to look for new recovery technologies that can be used for electricity production or alternative efficient applications. For the oil and gas industry, natural gas that would otherwise be flared can instead be used to produce heat power that is able to be recovered for electricity generation, thus significantly reducing emissions.
Flaring gas can be reduced and/or recovered by means of different techniques, including, i.e., redistribution in the natural gas distribution networks, transported via pipeline (Piped Natural Gas -PNG), re-injected for enhanced oil recovery, used as feedstock for the petrochemical manufacturing, and used for electricity generation [7]. The latter technique was the focus of some recent studies and is the subject of the present investigation. For example, Heidari et al. [8] compared two novel methods for generating electrical power using the flare gas with a flow rate from 0 to 2.14 kg/s. The first method is burning the mixture of the flare gas and a conventional fuel, while the second method is based on sending the flare gas to an intermediate stage of a gas turbine after burning it in a combustor. Results
show that the first scenario is preferable from technical and economic aspects for all of the flare and natural gas flow rates except when the amount of the flare flow rate in the plant is lower than 0.8 kg/s. The same authors [9] also compared two scenarios of electrical power generation-based flared gas. The first scenario assumed a gas turbine working in a simple Brayton cycle while the second scenario considered a simple cycle of the gas turbine-based Fog method. The comparison-based technical and economic aspects showed that the second scenario generates higher power with a difference of about 1.75 MW while the first scenario is more economically acceptable. Ojijiagwo et al. [10] and Ojijiagwo et al. [11] studied the technological and economic implications of the use of gas to wire (GTW) technology to manage gas flare for electricity generation, particularly in Nigeria. The economic analyses point out a potential net profit of £2.68 billion from flare gas prevention. The prevented flare gas can substitute the initially daily feed gas of 46.5 MCM required for gas turbines to generate around 7500MWof electricity. Anosike [12] simulated and compared different gas turbines used for converting waste from flared gas and from pure natural gas in Nigeria. The comparison showed that both fuels have a similar performance and the recovered flared gas can be used effciently in electricity generation using conventional gas turbines. Rahimpour et al. [2] investigated three methods: Gas-to-liquid (GTL) production, electricity generation with a gas turbine, and compression and injection into the refinery pipelines, via simulation and economic evaluation for Asalooye gas refinery to recover and reuse flare gases. Results showed that 48,056 barrels per day of valuable GTL products are produced by the GTL method. The electricity generation method provides 2130 MW electricity and the gas compression method provides a compressed natural gas with 129 bar of pressure for injection to the refinery pipelines. In addition, the economics evaluation results show that the gas compression technique is the most economical approach in Asalooye gas refinery with a medium capital investment owing to lower capital investment costs and higher return investment rate. Rahimpour et al. [13] did the same work for Farash band gas refinery. Results showed that electricity generation is the most appropriate solution economically. Hajizadeh et al. [14] evaluated and simulated the feasibility of three methods for flare gas recovery (FGR) using Aspen HYSYS and Aspen EDR simulation software in a giant gas refinery in Iran.
These methods include liquefaction, LPG (liquefied petroleum gas) production, and a gas compression unit. The liquefaction and LPG production units existed in the plant and can be used for FGR. Results indicate that operating a flash drum at 1 barg of pressure leads to maximum liquid extraction from flare gas, while operation at 0.75 barg gives maximum LPG production. Using the FGR methods, more than 80% of flare gases can be recovered, which stops about 205 ton/day CO2 equivalent emission. The economic analysis showed that the rate of return (ROR) for liquefaction and LPG methods is above 200%. Al-Fehdly et al. [15] proposed an alternative energy utilization solution that can reduce the energy waste as well as the carbon footprint of crude oil production estimated in Iraq. This solution is to use the flared gas in generating electricity instead of the adopted method of using fossil fuel, which potentially saves about 50 million tons of carbon dioxide annually as per today’s production rates.
Adekomaya et al. [16] made the Nigerian government aware of the enormous gap in the power supply and demand in order to control the generation of electricity. They highlighted the linkages between gas flaring and its impact on energy growth and sustainability. Iora et al. [17] focused on the on-site electricity generation from an annual average yield of 1150 Nm³/h of associated gas. The analysis was carried out by comparing, both from the economic and environmental points of view, various power
plant technologies for the generation of electric power in the proximity of the oil field. It turned out that adopting a scheme with non-derated internal-combustion engines (ICEs) fed by treated gas, and partial gas flaring, the most cost-effective result was obtained, showing an important payback time of about 5 years and an internal rate of return (IRR) of 42.2%. Tahouni et al. [18] presented a novel methodology of a fuel gas network (FGN) based on the model of Hasan el al. [19]. They developed new constraints for flaring emissions mostly for CO2 emissions. Additionally, they proposed a profit-based retrofit model for the integration of flare gas streams in FGNs. The refinery case study proved that the use of a flared gas stream to the network, the novel model of FGN, can reduce energy costs and flaring emissions. Comodi et al. [20] investigated the deployment of a liquid ring compressor to treat flare gas and reuse it. The flare gas recovering flow rate of 400 kg/h was performed. Such a solution was economically profitable with an interesting payback time estimated at less than 3 years.
The generation of electrical power can be achieved by means of different alternative and well-developed techniques, such as the steam Rankine cycle (SRC), which uses the dissipated heat from the waste heat boiler to generate steam that drives a turbine [21]. The organic Rankine cycle (ORC) is also a recently developed technique, which uses organic working fluids instead of water. These fluids are generally selected based on the investigated application, temperature levels, and the environmental impact in terms of the ozone depletion potential (ODP) and global warming potential (GWP) [22].
As a negative consequence of the natural gas flaring and the new initiatives endorsed by the World Bank to some concerned countries and oil and gas companies to end routine gas flaring by 2030 [23], the objective of this study was to propose a thermodynamic analysis-based ORC system for waste heat recovery from gas flaring in Algeria. Contrarily to pollutant information emissions from gas flaring activities that can be provided by a satellite [24], in situ potential estimation of the flare gas heat source is very difficult because of challenging measurement due to the noticeable changing of gas composition at high flow velocities as reported by Emam [25]. Therefore, Ziyarati et al. [26] implemented one model, allowing a good estimation of both the flow rate and gas composition of gas feeding the flare system.
The present work focused on the assessment of a toluene ORC system for power generation from an annual average yield ranging from 100 to around 1000 Nm³/h of associated flaring gas [17]. Because of the high velocities and flow rate variation of flare gas, the ORC system risks off-design operating conditions. This is the main reason for which toluene was selected as the working fluid for this application since toluene figured among the fluids with the highest net power outputs at low loads [27] and supports high temperature ranges over 300 C° [28]. An integration of an absorption chiller activated by the condenser rejected heat was rapidly investigated with important cooling capacities.
In addition, and to the best of our knowledge, there is a lack of research studies on natural gas flaring and more particularly in Algeria. Therefore, this study takes up this challenge by considering and applying the present proposed ORC system to a potential application for waste heat recovery in an Algerian petrochemical unit. Publications dealing with ORC application for flare gas waste heat recovery are very limited and no detailed thermodynamic analysis-based ORC system for the waste heat recovery from gas flaring applications is available. Thus, the focus of the present paper was to contribute to the enhancement of knowledge about the feasibility and the application of this technique for waste heat recovery from a flaring gas source in a well-known oil- and gas-producing country, such as Algeria.
Reducing the flare is identified as a key action for the implementation of the sustainable development goals [29] and to comply with the endorsed zero routine initiative and the Paris agreement, declining as Nationally Determined Contribution (NDC) in Algeria [30].
Therefore, the rest of the paper is devoted to presenting the thermodynamic model in terms of energy and exergy analysis for both flare gas and ORC systems. Thereafter, the simulation results are presented and discussed. The conclusions are noted at the end of the paper, pointing out an important potential for ORC applications even for electricity production and cooling owing to a possible coupling with an absorption chiller.

2.Thermodynamic Model
Thermodynamic analysis concerns a flare gas waste heat recovery system using a toluene ORC cycle as depicted by Figure 1. The thermodynamic study was performed based on a couple of assumptions summarized as follows:

● Steady state operating mode of the ORC cycle [31,32]
● Neglecting pressure drops at each side of the heat exchangers [31,32]
● Neglecting both variation of both kinetic and potential energies [31,32]
● Turbine and feeding pump isentropic efficiencies fixed at 0.8 [28]
● Tev = 300 ^○C, considered as the highest temperature for the high-temperature working fluid [28]
● Tc = 120 ^○C; fixed based on the corresponding saturation pressure, Psat = 1.31 bar > Patm
● Ideal conversion from mechanical to electrical power
● Sub cooling and super heating respectively fixed at DTsub = 5 ^○C [33] and DTsup = 0 ^○C [32] for
the basic configuration
● Flare gas considered as semi perfect, meaning that the thermophysical properties depend only on
the temperature contrarily to the ideal gas with constant thermophysical properties.

Then, both the specific enthalpy and entropy are defined respectively as:

.The expression of specific entropy is obtained when neglecting the pressure drops

2.1. Specific Heat Capacity Model of the Flare Gas
The specific heat capacity of combustion products, flare gas, depends on the temperature variation [34]; this is why the gas is qualified as semi-perfect, and considering it as constant may disturb a good quantification of the available heat of the source. These risks also have a direct impact on the enthalpy and entropy calculations since both terms are defined based on the specific heat capacity.
The thermodynamic database used to perform the required calculation of the ORC, Cool Prop, is not able to be used directly to prevent accurate enthalpy and entropy calculation for the present flare gas composition since such a specific mixture is not available within the mentioned data base. Thus, the calculation is made possible through two mains steps: Defining the typical flaring gas composition within the Cool Prop tool, and then deducing its specific heat. After this, a sensitive analysis on the computed specific heat is performed and a fitting curve for the variation of the specific heat versus temperature is obtained. It should be noted that the elementary chemical compounds of the typical flare gas composition are all available within the Cool Prop database.
A typical flare gas composition was considered for the present work as reported previously by Emam [25]. Such composition was assumed for the present preliminary study. However, experimental measurements are highly recommended when a physical ORC deployment is expected in order to assure an accurate-sizing step of the whole ORC solution during the tendency modeling step.
As mentioned previously, the composition of the flare gas was introduced within CoolProp [35] for the calculation of specific heat capacity for a range of temperature sources. The interpolation of the different points of Cp allowed implementation of the next fitting curve expression for which all coefficients are defined in Table 1.

Therefore, the integration of this last expression will allow accurate calculation of the enthalpy
:and entropy (inlet/outlet). Their respective expressions are given then

2.2. ORC Cycle Thermodynamic Model
The thermodynamic model of the ORC cycle deals with energy and exergy analysis by considering all abovementioned assumptions.
2.2.1. Energy Analysis
The thermodynamic model was carried out based on the previous work of Le et al. [31].
As shown in Figure 2, the subcooled organic working fluid is firstly pressurized to the high pressure of the steam generator. This thermodynamic transformation required mechanical power, such as:

The working fluid is preheated and then evaporated into saturated steam. This transformation is made possible by recovering the heat available in the flare gas. Consequently, a waste heat is recovered to feed freely the ORC system. Thereby, the temperature of flue gas is drastically reduced, leading to an important reduction of the thermal pollution. The overall thermal power absorbed at high pressure by the preheater and the evaporator is calculated as:

where Q_ev and Q_pre represent respectively the heat power absorbed by the evaporator and preheater.
The selected working fluid, Toluene, presents a negative slope in the T–s diagram, Figure 2; i.e., dry fluid. Therefore, superheating is no longer required for this basic configuration. Thus, the turbine expansion power can be formulated as:

The expanded steam leaving the turbine is then introduced within the condenser to be respectively cooled, condensed, and then subcooled to protect the feed pump. The rejection power at low pressure occurring during these steps is calculated:

Consequently, the thermal performance of the ORC system activated by the recovered heat of the flare gas initially discharged to the atmosphere is defined as follow:

2.2.2. Exergy Analysis
The quality of energy analysis is improved through the exergy study. The exergy study focuses on both consumed and destroyed exergy within each element of the ORC cycle. The standard conditions are considered for the dead state.
Therefore, the supplied exergy during the heating step is provided by the heat source. It is expressed as:

Then, the working fluid absorbs only one part of the available exergy. Consequently, the absorbed exergy by the high pressure exchanger, composed of both the preheater and evaporator, can be calculated as:

While, the destruction of exergy is quantified by:

The generated steam leaving the evaporator is directed towards the expansion device. This means that available exergy supplied for the expansion process becomes:

This last expression of the available exergy can be decomposed respectively in two terms:
The useful exergy that represents the effective output performed by the turbine (Equation (15)) and the exergy destruction occurring within the turbine (Equation (16)):

After the expansion process, the working fluid undergoes transformations leading to the supply of exergy to the cooling medium; this exergy is defined as:

On the other hand, the cooling medium receives only part of the exergy formulated as:

The destruction of exergy during the heat rejection in the condenser can be expressed by:

The subcooled fluid leaving the condenser is pressurized to the high pressure of the evaporator.
This requires an exergy supply defined as:

Therefore, the working fluid receives the following useful exergy

The pumping processes generate exergy destruction estimated by the following relation:

Finally, the overall exergy destruction occurring throughout the ORC cycle is expressed as:

Then, the whole system exergy efficiencies defined by:

We also define the pressure ratio as follows:

:Another ratio, the evaporator heat ratio, is defined for the specific need of the present study

3.Results
The obtained results are presented in four separate subsections. The three first subsections focus on the sensitivity analysis of three parameters, including respectively the evaporation temperature, heat source inlet temperature, and super heating temperature. The final subsection is allocated to the integration of the absorption chiller and its impact on the overall performance of the proposed system.
3.1. Evaporation Temperature Sensitivity Analysis
Figure 3 points out a proportional correlation for both the thermal, exergy performances, and mechanical power produced by the turbine when the evaporation temperature increases.
The maximum thermal and exergy performances of 15.8% and 35%, respectively, and mechanical power output of 233 kW are reached with the temperature of 300 ^○C. Indeed, the increasing of the evaporation temperature conduct to recover a higher heat power thus leads to a reduction of the exergy destruction within the evaporator. The higher enthalpy intensity of the output steam leaving the evaporator maximizes the power of the turbine and increases the irreversibility, as shown in Figure 4.
Consequently, the exergy destruction in the turbine rises slightly, with the same trend as the destruction of exergy in the condenser. However, the reduction of the evaporator’s exergy destruction is faster so that the total irreversibility of the whole system passes from about 305 to 185 kW for the evaporation temperature ranges of 150 to 300 ^○C.

In terms of the exergy destruction ratio, the higher value of the evaporation temperature highlights that the exergy destruction is dominated by the condenser and evaporator, with a ratio of 39%. This ratio is about 21% and 1% for the turbine and pump, respectively, as depicted in Figure 5.

Moreover, the increasing of the evaporation temperature points out that the pressure ratio (Pev/Pc) becomes higher from Figure 3b while the ratio Qev/Qpre reduces as represented in Figure 6.
The higher pressure ratio risks many stages of the ORC turbine being required, i.e., more expensive.
When the evaporation heating is dominated by the preheating step Qev Qpre < 1, this leads to the higher thermal coefficient not being taken advantage of due the evaporation itself (phase change enthalpy).
Consequently, a greater area should be implemented in the pre-heater to offset the high heat transfer coefficient of the evaporation step. Thus, the cost of the pre-heater risks being much higher with a direct impact on the energy unit cost ($/kWh). This detail was not developed in the present work and it will be considered in our future investigation. The present work concerns only a preliminary study to point out the potential of an ORC application to produce electricity based on flare gas within the Algerian context.

3.2. Heat Source Inlet Temperature Sensitivity Analysis
The sensitivity analysis based on the heat source inlet temperature was performed with a basic ORC configuration (Tev = 300 ^○C and Tc = 120 ^○C).
The sensitivity analysis notes that the exergy efficiency and flare gas flow rate vary inversely with an increasing temperature heat source, as shown in Figure 7. The deterioration of the energy performance is mainly due to the generated irreversibility within the evaporator that becomes more important with an increasing heat temperature source as presented in Figure 8. As the ORC cycle is fixed, the total exergy destruction of the ORC system is only and directly affected by irreversibility within the evaporator. It follows the same increasing trends already observed with the evaporator.

3.3. Super Heating Temperature Sensitivity Analysis
The sensitivity analysis of the super heating temperature was carried out by fixing the inlet heat source temperature, this = 400 ^○C, for the basic ORC configuration.
The results, as shown in Figure 9, note the reduction of the turbine-generated power when the heat source temperature rises. The super heating step allows a higher recovery amount of the same available thermal power of the heat source. In other terms, the absorbed exergy is improved for the evaporator, decreasing its exergy destruction, as can be observed in Figure 10. However, superheating involves an important exergy destruction within the condenser and then the total exergy of the whole system. Consequently, this fact reduces the exergy performances.

3.4. Turbine Efficiency Sensitivity Analysis
The increasing of the isentropic efficiency of the turbine improves both thermodynamic performances and thus the improvement of the power output of the turbine, as shown in Figure 11a.
This is due to diminution of the irreversibility within the turbine, then in the condenser, and consequently the total exergy destruction as observed from Figure 11b. No destruction variation was observed for the high pressure heat exchanger (preheater + evaporator) and for the pump as these compounds are independent of the turbine.

3.5. Integration of Absorption Chiller
The rejected heat at the condenser still presents an important heat potential especially for activating a sorption chiller. A sorption chiller can use either a solid solution—adsorption chiller—or liquid solution in the case of an absorption chiller. As reported by several authors [36,37], the coefficient of performance (COP) and cooling capacity of an absorption chiller are greater than the adsorption technology. Basically, the single effect COP of the absorption chiller ranges from 0.5 to 0.73 for an operating temperature comprised between 60–110 ^○C. The cooling capacity for commercial applications varies from kW to MW, where the COP ranges from 0.25 to 1.2 depending on both the desired evaporation temperature of the chiller and the inlet temperature [38].
Indeed, the activation of the absorption chiller by the condenser’s rejected heat improves the overall performance of the system and allows it to meet the cooling demand of both petrochemical units and offices initially produced by consuming even gasoline, gases (oil production well), or network electricity in the case of a petrochemical plant. For a fixed COP of 0.5 and absorber feeding temperature (Tcso = 100 ^○C), the proposed basic ORC system produces electrical power of 233 kW and rejects about 1180 kW, with a thermal performance of 15.8%, thus leading to a cooling capacity of about 590 kW.
Therefore, the ORC absorption chiller coupling enhances the performance of the whole system to almost 59%. Depending on the flaring capacity of each plant, a low flaring rate in the petroleum downstream sector compared to the high flaring rate in the upstream sector, the electricity and cooling capacity can vary as depicted in Figure 12. At the maximum flare gas flow rate, the cooling capacity and electrical power output can reach 5.9 and 2.3 MW, respectively.

Concerning the whole exergy performance of the combined systems, this part is not developed as it requires more details and it will be carried in future investigations.

Conclusions and Perspectives
The presented paper investigated the implementation of the ORC cycle as a key solution for flare gas waste heat recovery. The study focused on thermodynamic performance studies in terms of energy and exergy balance. This was followed by sensitivity analysis, aiming to highlight the most important parameters with direct impact on the whole system’s performance.
With a fixed temperature of the inlet flare gas, the sensitivity analysis of the evaporation temperature pointed out the diminution of the total destroyed exergy, especially within the evaporator, and subsequently the improvement of the thermodynamic performances and the turbine power output.
The maximum evaporation temperature of 300 C led to higher energy and exergy performances, estimated at 16% and 35%, respectively, while the maximum turbine power reached 230 kW. Moreover, the analysis noted the fact that high temperature heat transfer can be dominated by a preheating step to the detriment of evaporation itself, causing an expensive cost for the evaporator.
The analysis of the inlet’s heat source temperature impact, flare gas, showed a proportional exergy destruction in the evaporator, and then for the whole system, when the heat source temperature was increasing. A direct impact was observed by the reduction of the exergy performance of the ORC system to about 29% when the heat source temperature passed from 400 to 600 C because of the exergy destruction occurring within the high-pressure heat exchanger.
The impact of the superheating temperature was investigated. As the toluene is a dry fluid, the super heating should be reduced at its minimum. Furthermore, superheating reduces all thermal performances of the systems and induces important exergy destruction, especially in the condenser.
The sensitivity analysis of the turbine eciency noted the improvement of both thermodynamic performances, total exergy destruction and turbine power output, when increasing the turbine efficiency.
Another solution consisting of the integration of an absorption chiller activated by the condenser’s rejected heat was carried out. The preliminary investigation highlighted the important potential of the ORC-absorption combined system to produce both electricity and cooling with a maximum performance of 59%. This power capacity varies from hundreds of kW in the case of a downstream petroleum application to the MW range for the upstream sector. Such a solution will be investigated deeply in future works to assess accurately the whole exergy performances of the system and to estimate the cost solution and its profitability in the Algerian market.

Author Contributions: Conceptualization, H.S., A.F. and M.F.; methodology, H.S., S.A. and M.F.; software, H.S.;
formal analysis, R.F. and M.F.; investigation, H.S. and A.F.; data curation, H.S.; writing—original draft preparation, H.S., A.F., S.A., R.F. and M.F.; writing—review and editing, H.S., A.F., S.A., R.F. and M.F.; visualization, H.S.; supervision, M.F. All authors have read and agreed to the published version of the manuscript.
Funding: This research received no external funding.
Acknowledgments: The authors would like to thank DCRD-SONATRACH and R20-MED for their respective support.
Conflicts of Interest: The authors declare no conflict of interest.

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Design Criteria Simulation of Flare Gas Recovery System

Abstract—During the oil and gas extraction and their refining processes, a large amount of gases are not used and then they will be sent to the flare networks. If the Flare Gases Recovery Systems (FGRS) is used, then we can recover the wasted energy and prevent the emission of greenhouse gases. In this paper, we studied design criteria of flare gas recovery system and steady sate and dynamic simulation of the FGRS. The steady state simulation results indicate that if the FGRS is used when one of these finery’s phases has been out of order, the recovery of 5916 (nm3/hr) of sweet natural gas, 24 (ton/hr) of gas condensates and production of 297 (m3/hr) of acid gas would be possible. Also, we studied the changes in the temperature of the gases sent to the flare during total shutdown of the refinery as well as the impact it had on FGRS behavior.

I. INTRODUCTION

DUE to the global population growth and increase in living standards especially in developing countries, the greenhouse gas emissions have been increased in recent years [1]. To fulfill the ever-increasing global demand for oil and gas, enormous quantities of co-produced gas are flared as a waste by-product and large supplies of gas have emerged. Although this process ensures the safety of the rig by reducing the pressures in the system that is resulted from gas liberation, it is very harmful to the environment. It has been the source of much controversial debate as not only wasting a considerable amount of valuable energy but also contributing to severe environmental problems in the petroleum and related industries [2].
It is generally accepted that carbon dioxide is a greenhouse gas and contributes to global warming. About 75% of the anthropogenic emissions of carbon dioxide come from the combustion of fossil fuels [3]. Thus, a reduction in emission of greenhouse gases is a crucial issue. One way to reduce CO emissions is carbon capture and storage, which involves capturing of CO at emission sources and storing it where it is prevented from reaching the atmosphere [4]. A great emphasis has been placed on the source control in modern hydrocarbon processing operations. The technologies contributing to a reduction in the downstream level of source pollutants are costly, and the usually result in the destruction or consumption of valuable hydrocarbon compounds. One exception, where the hydrocarbons are not destroyed, is vapor recovery. In vapor recovery, recovered materials can be recycled to the processing operation, or use as fuel system [5].

A.Environmental Effect of Flaring

There are many gas refineries around the world that send huge amounts of gas to the atmosphere through flaring. CO2 emissions from flaring have high global warming potential and contribute to climate change. Flaring also has harmful effects on human health and the ecosystems. The low quality gas that is flared releases many impurities and toxic particles into the atmosphere during the flaring process. Acidic rain, caused by sulfur oxides in the atmosphere, is one of the main environmental hazards which results from this process [6].

According to the World Bank [7], the annual volume of natural gas flared or vented in the world for the year 2010 amounted to more than 120 billion cubic feet. So according to research performed by the World Bank’s Global Gas Flaring Reduction Partnership (GGFR), the equivalent of almost one third of Europe’s natural gas consumption is burned in flares each year which contributes to about 400 million tons of carbon dioxide emission to the atmosphere (roughly 1.5% of the global CO emissions) [8]. Pollutants discharged from flares also, include sulfur oxides (Sox), nitrogen oxides (NO) and volatile organic components (VOC). The impacts of flare emissions therefore include the health impacts associated with exposure to these pollutants, and the ozone forming potential (and hence indirect health impacts) associated with hydrocarbon and NOx emissions, and the greenhouse gas effects of methane and CO emissions [9].

B.Gas Flaring

Flares are combustion devices designed to safely and efficiently destroy waste gases generated in a plant. In refinery operations, flammable waste gases are released from processing units during normal operation and process upset conditions. These waste gases are collected in piping headers and delivered to a flare system for safe disposal. A flare system has multiple flares to treat the various sources for waste gases [10]. The flare gas can come from exhaust of utilities, safety valves connections or vent connections. Gas composition depends on the equipment and utilities which are connected to the flare networks. There is in fact no standard composition and it is therefore necessary to define some group of flare gas according to the actual parameters of the gas. There is also a great variations in pressures of this flare gas and flare networks

Flares are primarily safety devices that prevent the release of unburned gas to atmosphere; these gases could burn or even explode if they reached an ignition source outside the plant. Two levels of flaring that are of interest. The first is flaring that occurs during a plant emergency. This can be a very large flow of gases that must be destroyed, where safety is the primary consideration. These flows can be more than a million pounds per hour, depending on the application. The maximum waste-gas flow that can be treated by a flare is referred to as its hydraulic capacity. The second level of flaring is the treatment of waste gases generated during normal operation, including purge gas, sweeping gas and planned decommissioning of equipment [10].

The implementation of no-flare design will have a great impact in reducing the emissions from production. With increasing awareness of the environmental impact and the ratification of the Kyoto protocol by most of the member countries, it is expected that gas flaring will not be allowed in the near future. This will require Significant changes in the current practices of oil and gas production and processing [6]. Ghazi et al. (2009) investigated the recovery of flared gas through crude oil stabilization by a multistage separation with intermediate feeds [11]. Rahimpour and Jokar (2012) investigated the best method for recovering the flare gas of Farashband gas processing plant from the economic point of view. Zadakbar et al. (2008) presented the results of two case studies of reducing, recovering and reusing flare gases from the Tabriz Petroleum Refinery and Shahid Hashemi-Nejad (Khangiran) Natural Gas Refinery, both in Iran [12].

II. FLARE GAS RECOVERY SYSTEM

Environmental and economic considerations have increased the use of gas recovery systems to reclaim gases from vent header systems for other uses. With the help of technological advancement in this field, now we can dramatically reduce the volume of burned gases in refineries using a gas compression and recovery system. Flare gas recovery systems eliminate emissions by recovering flare gases. Vent gas recovery systems are commonly used in refineries to recover flammable gas for reuse as fuel for process heaters [13].

Even in most advanced countries only a decade has passed from flare gas recovery technology, thus the method is a new methods for application in refineries wastes. Of such countries active in flare gas recovery are USA, Italy, the Netherlands, and Switzerland. Most FGR system has been installed based primarily on economics, where the payback on the equipment was short enough to justify the capital cost. Such systems were sized to collect most, but not all, of the waste gases. The transient spikes of high gas flows are typically very infrequent, meaning normally it is not economically justified to collect the highest flows of waste gas because they are so sporadic. However, there is increasing interest in reducing flaring not based on economics, but on environmental stewardship [10].

A. Design Criteria of FGR system

The FGR system is designed to capture waste gases that would normally go to the flare system. The FGR system is located upstream of the flare to capture some or all of the waste gases before they are flared. There are many potential benefits of an FGR system. The flare gas may have a substantial heating value and could be used as a fuel within the plant to reduce the amount of purchased fuel. In certain applications, it may be possible to use the recovered flare gas as feedstock or product instead of purchased fuel. The FGR system reduces the continuous flare operation, which subsequently reduces the associated smoke, thermal radiation, noise and pollutant emissions associated with flaring. Fig. 1 shows conceptual design for a FGR system [14]. The basic processes of the FGR system are [10]:

1) Process vent gases are recovered from the flare header.
2) Gas compressors boost the pressure of this gas.
3) Recovered gas is discharged to a service liquid separator.
4) Separated gas may pass through a condenser where the easily condensed constituents may be returned as liquids feedstock while the components that do not easily condense are returned for use as fuel gas after scrubbing for contaminant removal, such as H2S.

1.Sizing
Flare gas recovery systems are seldom sized for emergency flare loads. Usually, economics dictate the capacity be provided for some normal flare rate, above which gas is flared. Flare loads vary widely over time, and the normal rate may represent some average flare load, or a frequently encountered maximum load. Actual loads on these systems will vary widely, and the must be designed to operate over a wide range of dynamically changing loads. Flare gas recovery systems often are installed to comply with local regulatory limits on flare operation and, therefore, must be sized to conform to any such limits [14].

2.Liquid Seal Drum
The principal potential safety risk involved in integrating a flare gas recovery system is from ingression of air into the flare header, which can be induced by the compressor suction. This could result in a flammable gas mixture being flashed off inside the system from flare pilots [15]. The connections through which the compressors will take suction on the system, and additional seal drums which will provide extra safety against air leakage into the flare system and allow the buildup of flare header pressure, during compressor shutdown or flare gas overload. Also, the compressor control system does not affect the flare system pressure and thus its design will be able to avoid low pressure suction in the flare system during normal operation. The FGR system must be operate over ranges, usually within very narrow suction pressure bands. A typically system might operate over a suction pressure range of 2 to 5 inches of water to 10 to 12 inches of water [14]
The liquid seal vessel (LSV) is a critical equipment item for safe and successful operation of the FGR System. LSVs used in FGR Systems are termed “deep liquid seals” with seal water depth of 30 inch or more. This provides adequate pressure control range for FGR System operation. It is crucial that the LSV is properly designed and sized to handle the changes in flow and transition safely from the normal flare gas flow rates to any emergency flare gas flow rate. Typically, the LSV is installed downstream of the Knock-Out Vessel that is usually near the base of the flare stack [16]
Unwanted seal fluid wave dynamics in such drums have been known to give operating problems. These problems may include vibration, suction pressure instability, and cyclic flare flame puffing. Proper attention to the asymmetry of internals and wave dynamics would avoid these problems. Although water appears to be widely accepted as the conventional seal fluid, other fluids such as stove oil or glycol water mixtures are possible alternatives. Fluid selection requires consideration of freeze protection (in cold climates), hydrocarbon/water separation, implications of carryover, cost, availability, and disposal [17].

3.Selection Type of Compressor
Several compression technologies are available for FGR Systems. Proper selection of the type of compressor for each application is very important. Although, theoretically, any kind of compressor can be used, some kinds have earned broader acceptance in this service than others [18]. Over the last 35 years various companies have used several compressor types including Dry Screw Compressors (DSC), Sliding Vane Compressors (SVC), Reciprocating Compressors (RC), Liquid Ring Compressors (LRC) and Oil Injected (or Oil Flooded) Screw Compressors (FSC) both single and dual screw designs. The chosen compressor technology greatly affects the FGR System initial cost, FGR System physical size, and FGR System operating and maintenance expense [16]. To compress gases and to design flare gas recovery unit, in general, liquid ring compressors or reciprocating compressors are used. Advantage of first type is that gas is cooled during compression by heat transfer of gas through water inside compressor (usually water). It is possible to use amine instead of water in such compressor to separate hydrogen sulfide from flare gases. Reciprocating compressors are purchased easily than the first type, also spare parts provision, repair and maintenance is much easier. If using reciprocating compressors, please note that it will explode if temperature exceeds over allowable limit [19]. Piston compressors are available with one or more cylinders and one or more stages. Multi-cylinder compressors are used for higher outputs, multistage compressors for higher pressures. The gas compressed in the cylinder in the first stage (low pressure stage) is cooled in the intermediate cooler and then compressed to the final pressure in the second stage (high pressure cylinder [20]).

4.Compressor Control
The conventional compressor control strategy calls for adjusting the (net) discharge flow of the compressor to maintain a constant suction pressure. A suction pressure of about 1 psig is high enough to prevent air ingress and low enough to allow the existing relief valves to perform properly. The suction pressure is determined by the seal liquid height in the seal drum. The sense point for the pressure control instrumentation should be in the compressor suction drum. This control signal can prompt a recycle spillback-to-suction to help control suction pressure. Other levels of control sophistication may also be considered. For equipment protection, an automatic shutdown or lock-up system should be incorporated. The actual protection philosophy will depend on the specific machine, components, and operating philosophy. It should be noted, however, that an overly complicated lock-up system can be more trouble than it is worth. Nuisance trips of the system protection devices may occur so frequently as to penalize the on-stream factor [21].

5.Capacity of FGR
The normal flare loads vary widely depending on refinery throughput and operating mode. To enable recovery of over 90 percent of the total annual flare load and keep flaring to a practical minimum, the compression facilities should be designed to handle about 2 to 3 times the average normal flare load. Other plants, such as chemical plants, may have lower normal variation in flare rates. For this reason, the installations may be sized for a lower flow range
The flare gas recovery facilities should be designed to handle the normal range of molecular weight of the flare gases. This normal range may be best determined by numerous spot determinations over an extended period of typical, steady plant operation. The extremes that occur only during rare upset or turnaround conditions need not be included [21]
If the volume of flare gas that is relieved into the flare system exceeds the capacity of the FGRS, the pressure in the flare header will increase until it exceeds the back pressure exerted on the header by the liquid seal. In this event, excess gas volume will pass through the liquid seal drum and onto the flare where it will be burned. If the volume of flare gas relieved into the flare header is less than the total capacity of the FGRS, the capacity of the FGRS adjusts to a turndown condition. This is accomplished by turning off compressors and/or by diverting discharged gas back to the suction header through a recycle control valve. The compressor speed can also be varied. Control of the FGRS is automated with minimal requirement for direct operator intervention [22].

III. SIMULATION OF FLARE GAS RECOVERY SYSTEM
Flare gas recovery system is simulated in two steps. In first step, the system is simulated steady state, and the equipment specifications, the mass balance, the energy and a schematic of the process are obtained. In second step, the system is simulated dynamically and while one phase in refinery system is out of service, changes are studied. Fig. 2 shows the PFD of FGR system. According to a study conducted by Shell, the capacity of simulated FGR unit is equal to 90% of the normal capacity of flaring in the refinery [21]. Since the recovered gases are used in fuel gas system of the refinery, the compressor outlet pressure is considered as 7 Barg.

A. Study on the Dynamic Simulation of FGR System
At total shutdown of one of phases in the refinery, according to the control logic for discharge of different units, all units in the phase are discharged within 36 minutes. The range of changes in gas flow rate sent to the flare network is from 140621(Kg/hr) to 535034 (Kg/hr) [23]. In dynamics simulation of the FGR system, the effect of changing the temperature of the gas sent to the flare network on the performance of the FGR system is studied at total shutdown and discharge of one phase. As the temperature of gases sent to FGR system increases, the operating condition is changed for two-phase separator at the compressor inlet. Fig. 3 shows the changes in the condensate separation at separator before the compressor.

As the temperatures increases, the efficiency, and consequently the compression ratio, of the compressor is reduced. If the heat transfer in the intermediate and end coolers in the compressor is assumed to be constant during the dynamic changes, the temperature of the compressor outlet increases due to the increase in the temperature of the gas entering the compressor. Fig. 4 shows the changes in temperature, pressure and flow rate at the compressor output while the temperature of the gas sent to the compressor is increased.

Due to temperature variations in the flow entering the three-phase separator, temperature and pressure in the separator are change greatly. The combination of the flow at the separator outlet has also variations. As the temperature of the gas discharging the compressor increases and the pressure decreases, the temperature and the pressure at the tree-phase separator show increasing and decreasing trends, respectively. Fig. 5 shows the variations temperature and pressure in the three-phase separator as the temperature increases and the pressure decreases.

IV. CONCLUSION
There is growing interest in minimizing flaring, in part due to the pollution emissions generated by flaring and potentially significant emission sources within a plant. The flaring reduction has high priority as it meets both environmental and economic efficiency objectives. There are many methods for minimizing gas flaring in oil and gas refineries. In this paper we studied design criteria of flare gas recovery system and steady sate and dynamic simulation of the recovery system for the gas sent to the flare in a sample gas processing plant. The steady state simulation results indicate that if the flare gas recovery system is used when one of these finery’s phases has been out of order, the recovery of 5916 (nm3/hr) of sweet natural gas, 24 (ton/hr) of gas condensates and production of 297 (m3/hr) of acid gas would be possible.
Also, we studied the changes in the temperature of the gases sent to the flare networks during total shutdown of the refinery as well as the impact it had on FGR system behavior. The results are shown in separate graphs. It is obvious that the efficiency of the compressor is reduced due to the increase in the temperature of the gas sent to the flare network; therefore, the value of separation in two and three-phase separator shows a drastic change which is shown in the graphs.

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[12] Zadakbar O., Vatani, A., Karimpour, K., 2008. Flare gas recovery in oil and gas refineries, Oil Gas Sci. Technol. – Rev. IFP 63, pp. 705-711.
[13] Zadakbar O. K.K., Zadakbar A. (2006) Flare Gas Reduction and Recovery, The First National Specialty Conference on Gas, Iran, Oct. 30-31.
[14] API, Guide for Pressure-Relieving and Depressuring Systems, Recommended Practice RP 521, Fourth Edition, Washington, DC, March 1977.
[15] Tarmoom I.O. (1999) G.C.a.F.M., Paper SPE 53321, SPE Middle East Oil Show, Bahrain, Feb. 20-23.
[16] Blanton, R.E., Environmentally and Economically Beneficial Flare Gas Recovery Projects in Petrochemical Facilities, Presented at the National Petroleum Refiners Association Environmental Conference , San Antonio ,September 2010.
[17] Paper in Oil & Gas journal – February 14, 1972, Pages 91,”What Is Flare’s Proper Purge Rate?” by R.D. Reed, lohn ink Co., Tulsa.
[18] Paper in Oil & Gas journal – April 28, 1980, pages 98-102, “Flare-gas System Can Be Designed to Recover a Profit for Plant” by D.O. Livingstone, Polysar Ltd., Ontario.
[19] Younessi S., Omidkhah, M., Tarighaleslami, A., Study on flare gas recovery (FGR) to minimize wastes and economic benefits., The 17th Regional Symposium on Chemical Engineering (RSCE2010), November 1, 2010.
[20] Brown, R.N., 2005. Compressors: Selection and Sizing, third ed. Elsevier Science & Technology Books.
[21] Allen G.D., Wey, R.E., Chan, H., Flare gas recovery in shell Canada refineries, The Fifth Industrial Energy Technology Conference, Houston, April 1983.
[22] R. Schwartz,J. White, and W. Bussman, Flares, in The John Zink Combustion Handbook, ed. C. Baukal, CRC Press, Boca Raton, FL, 2001, Chapter 20.
[23] Asalooye Gas Refinery Data from Pars Oil and Gas Company, 2014. Asalooye, Iran.
International Conference on Chemical, Food and Environment Engineering (ICCFEE’15) Jan. 11-12, 2015 Dubai (UAE)

گاز طبیعی شامل هیدرورکربن های مختلفی است، متان 85 تا 95 درصد گاز طبیعی را تشکیل می دهد. البته با توجه به مشخصات فنی میدان گازی (Non-Associated Gas) و نفتی-گازی (Associated Gas)، سایر ترکیبات هیدروکربوری از جمله اتان، پروپان، بوتان، پنتان، هگزان و حتی سایر ترکیبات سنگین تر که به عنوان NGL نیز شناخته می شوند، در گاز استحصالی میادین وجود دارد. به طور معمول گاز طبیعی دارای عناصر غیرآلی همچون نیتروژن، هلیم، کربن دی اکساید و هیدروژن سولفاید نیز می باشد که نیاز است قبل از انتقال به مبادی مصرف در مجتمع های پالایشگاهی مورد تصفیه و فراورش قرار گیرد.
ایران عزیز با داشتن ۳۵ تریلیون مترمکعب ذخایر گازی، در رتبه اول در بین کشورهای دنیا قرار دارد. روسیه و قطر به ترتیب با ۳۲.۶ و ۲۴.۵ تریلیون مترمکعب در رتبه های دوم و سوم قرار گرفته اند. ترکمنستان با ۱۷.۵، ایالت متحده آمریکا با ۹.۸ تریلیون مترمکعب، عربستان صعودی با ۸.۲ و امارات متحده عربی نیز با ۶.۱ تریلیون مترمکعب در رتبه های چهارم تا هفتم از حیث ذخایر گازی در بین کشورهای دنیا قرار دارند. کشورهایی همچون ونزوئلا، نیجریه و الجزایر نیز به ترتیب با ۵.۶، ۵.۱ و ۴.۵ تریلیون مترمکعب ذخایر در رتبه های بعدی قرار دارند.
منطقه خاورمیانه سهم ۴۳ درصدی را در حجم ذخایر گاز طبیعی دنیا دارا می باشد. اروپای شرقی و مرکزی نیز با داشتن ۲۹ درصد سهم در ذخایر گازی دنیا در جایگاه دوم قرار دارد. آسیا پاسیفیک، آفریقا هر کدام با ۸ درصد، آمریکای شمالی با ۶ درصد، آمریکای جنوبی نیز با ۴ درصد سهم در ذخایر گازی دنیا در رتبه های بعدی قرار دارند. اتحادیه اروپا نیز تنها ۲ درصد از سهم ذخایر گازی دنیا را به خود اختصاص داده است.
با مقایسه سهم ذخایر با میزان مصرف گاز طبیعی در هر یک از مناطق دنیا می توان نتیجه گرفت که آمریکای شمالی با ۲۸ درصد، آسیا پاسیفیک با ۲۰ درصد، اتحادیه اروپا و خاورمیانه نیز هر کدام با ۱۴ درصد سهم عمده ای را در بخش مصرف گاز طبیعی دنیا دارا می باشند. در واقع عدم همپوشانی مناطق پرمصرف (پرجمعیت) با مناطق دارای ذخایر گاز طبیعی باعث شده است که کشورهای مختلف به منظور تامین این منبع ارزشمند و پاک انرژی، به دنبال ایجاد ائتلاف و البته روش های بهینه جهت تجارت این ماده باشند از جمله روش های انتقال این منبع انرژی می توان به موارد زیر اشاره نمود:

متان

• خط لوله انتقال گاز
• سردسازی و کاهش حجم گاز طبیعی (LNG)
• تبدیل گاز طبیعی به فراروده های هیدروکربوری مایع در فرایند GTL و صادرات محصولات
• تبدیل گاز طبیعی به محصولات پایه پتروشیمیایی از جمله متانول و آمونیاک و صادرات محصولات

در اولین گام و اولویت نیاز است با یک نگاه سیستمی (جامع بینی و آینده بینی) بین نخبگان فکری و اجرایی کشور تفاهم و اجماعی جهت اجرایی کردن اسناد بالادستی حوزه انرژی کشور از جمله سند ملی راهبرد انرژی صورت گیرد. بعد از آن می توان طی یک برنامه ریزی زمان بندی شده و البته عملیاتی اقدامات لازم را به منظور مدیریت تولید، تبدیل و فروش گاز طبیعی در بخش های مختلف مصرف را تدوین نمود.
به نظر می رسد، با وارد مدار شدن کلیه فازهای پارس جنوبی و افزایش در تولید گاز طبیعی نیاز باشد که برنامه ریزی دقیقی به منظور انتخاب راهبردهای مناسب جهت استفاده بهینه از این منابع خدادادی صورت گیرد در غیر این صورت مشابه سال های گذشته، الگوی مصرف کشور مشخص کننده راهبردهای تولید خواهد بود.

اتان

اتان با دو اتم کربن و 6 اتم هیدرژن بعد از متان جزء هیدروکربن های سبک و البته ارزشمند محسوب می شود. این ماده به طور عمده از سه مسیر گازهای همراه (NGL/Associated Gas)، میادین گازی (Ethan Recovery Plant) و پالایشگاه های نفت خام (Petroleum Refineries) تولید می گردد. دو منطقه آمریکای شمالی (ایالت متحده، کانادا و مکزیک) و خاورمیانه (ایران، عربستان، قطر، کویت، امارات و عراق) بیش از 80 درصد سهم تولید اتان در دنیا را دارا می باشند. خاورمیانه در سال 2012 چیزی در حدود 20 میلیون و 383 هزار تن و آمریکای شمالی نیز 26 میلیون و 900 هزار تن از 57 میلیون و 272 هزار تن تولید اتان در دنیا را به خود اختصاص داده اند.
پیش بینی می گردد در سال 2017 در دنیا 72 میلیون و 462 هزار تن اتان تولید گردد که بیشترین رشد را منطقه آمریکای شمالی دارا می باشد و در سال 2017 تقریبا 50 درصد از اتان تولیدی در دنیا در آمریکای شمالی خواهد بود.
بررسی ها حاکی از آن است که 99 درصد از اتان تولیدی در دنیا در واحدهای کراکینگ با بخار (Steam Cracking) به اتیلن تبدیل می شود. در سال 2014 در دنیا 137 میلیون تن اتیلن تولید شده است که 35 درصد از آن مبتنی بر اتان بوده است و پیش بینی می گردد تا سال 2019 بیش از 39 درصد از اتیلن تولیدی در دنیا از اتان باشد.
ایران با داشتن منابع غنی گازی می تواند به عنوان قطب تولید اتان و تبدیل آن به اتیلن در منطقه و دنیا باشد و البته این مهم نیز با طراحی خط لوله اتیلن غرب و مجتمع های تولیدکننده و مصرف کننده اتیلن قابل دستیابی است. اما باید این نکته را نیز در نظر گرفت که قابلیت تولید محصولات متنوع، با کیفیت و از همه مهمتر با هزینه ی نهایی کمتر؛ شرط لازم جهت ورود به فضای رقابت جهانی است. سوال اصلی این است که آیا طراحی، محصولات تولیدی و جانمایی واحدهای موجود در این طرح مبتنی بر فضای رقابت جهانی بوده است؟

گاز مایع

گاز مایع (LPG) ترکیب دو هیدروکربن سه کربنه (پروپان) و چهار کربنه (نرمال و ایزوبوتان) با نسبت های مختلف است. گاز مایع به عنوان یکی از محصولات اصلی و ارزشمند پالایشگاه های نفت خام و گاز غنی محسوب می شود. این فراورده ی هیدروکربوری ارزشمند دارای کاربردهای مختلفی است از جمله به عنوان سوخت در مصارف خانگی، تجاری و صنعتی، حمل و نقل و همچنین به عنوان خوراک صنعت پتروشیمی در واحدهای کراکر با بخار مورد استفاده قرار می گیرد.

مصارف خانگی (گرمایش و پخت و پز) با 49 درصد سهم قابل توجهی از مصرف گاز مایع را به خود اختصاص داده است. چین، هند و ایالات متحده سه کشور برتر در میزان مصرف LPG در بخش مصارف خانگی می باشند. صنعت پتروشیمی 23.5 درصد از گاز مایع تولیدی در دنیا را به عنوان خوراک مورد استفاده قرار می دهد. سایر مصارف صنعتی، سوخت خودرو و خوراک بنزین نیز هر کدام به ترتیب با 12، 9 و 6 درصد از گاز مایع تولیدی در دنیا را مصرف می نمایند.

منطقه خاورمیانه و ایالات متحده به ترتیب در رتبه اول و دوم تولید و صادرات گاز مایع در دنیا قرار دارند. ایالات متحده آمریکا در سال 2015 بیش از 20 میلیون تن گاز مایع به کشورها و مناطق مختلف دنیا صادر کرده است که در سال 2018 به 35 میلیون تن افزایش پیدا خواهد کرد. این در حالی است که صادرات خاورمیانه طی سال های گذشته تغییرات زیادی نداشته و در سال 2011، 34 میلیون تن برآورده شده است و پیش بینی می شود که در سال 2020 مجموع صادرات این منطقه به 38 میلیون تن برسد.

میعانات گازی

میعانات گازی (Condensate) به جریان هیدروکربنی مایعی گفته می شود که از پنتان و هیدروکربن های سنگین تر تشکیل شده و دارای مقدار گوگرد پایینی است و تقریبا 60 درصد از آن را نفتا (محصولی میانی با ارزش جهت تولید بنزین و خوراک واحدهای پایه و مادر صنعت پتروشیمی) و 30 درصد را نفتِ گاز تشکیل می دهد. میعانات گازی، یکی از محصولات ارزشمند استخراج شده از مخازن گازی بوده و قیمت آن کمی بالاتر از قیمت نفت خام در بازارهای جهانی است.
در تعاریف موجود به طور معمول میعانات گازی را با توجه به منبع و ترکیب درصد هیدروکربن های مختلف موجود در آن با عبارت های مختلف تعریف می گردد از جمله؛

• Lease Condensate
• Plant Condensate
• Pentanes Plus
• Natural gasoline

همان طور که اشاره شد، منابع مختلفی به منظور تولید میعانات گازی وجود دارد. برش های 5 و 6 کربنه و سنگین تر عمده ترکیب درصد میعانات گازی را تشکیل می دهد. پالایشگاه های گاز و کارخانه جات گاز مایع (NGL) منبع اصلی عرضه ی برش های فوق الذکر هستند. در واقع در میادین گازی در اولین مرحله، ترکیبات سنگین از سبک جدا می شود که ترکیبات سنگین که در فاز مایع نیز می باشند، به عنوان میعانات گازی (Plant Condensate) به بازار مصرف عرضه می شوند. در قیاس با نفت خام تنوع و مقدار ترکیبات آلاینده در میعانات گازی کمتر است (فلزات و ترکیبات نیتراته و گوگردی)، لذا همین موضوع سبب شده است که هزینه ی فراورش میعانات گازی در قیاس با نفت خام کمتر باشد.
در سال 2013 مجموع میعانات عرضه شده در دنیا 7 میلیون و 200 هزار بشکه بوده است که پیش بینی می شود که این عدد تا سال 2020 با نرخ رشد 3.2 درصد به 9 میلیون و 100 هزار بشکه خواهد رسید. 83 درصد از میعانات گازی تولید و عرضه شده در دنیا از نوع Lease Condensate می باشد که از تاسیسات سرچاهی میادین گازی-نفتی استحصال می شود.
دو منطقه ی خاورمیانه و آمریکای شمالی بخش عمده ی تولید میعانات گازی دنیا را بر عهده دارند. مطابق پیش بینی های صورت گرفته نرخ رشد تولید میعانات گازی در سه کشور قطر، عربستان و امارات متحده عربی طی سال های ۲۰۱۳ تا ۲۰۲۰ به ترتیب ۱.۷، ۳.۱ و ۱.۴ درصد در سال است و حجم تولید این کشورها به ترتیب به ۱ میلیون و ۲۰۰ هزار بشکه، ۸۰۰ و ۵۴۵ هزار بشکه در روز خواهد رسید.
در حال حاضر در کشور با احتساب منابع عرضه شده در پالایشگاه های گاز (از جمله عسلویه، ایلام، هاشمی نژاد و سایر واحدها) و کارخانه جات گاز و گاز مایع (NGL) روزانه چیزی در حدود 550 هزار بشکه میعانات گازی تولید و عرضه می شود که بخش عمده ای از آنها به مستقیما صادر می شود. هر چند با توجه به برنامه ریزی های صورت گرفته، طراحی و احداث طرح های جدید پالایشگاهی از جمله پالایشگاه ستاره خلیج فارس و طرح فراگیر سیراف در دستور کار قرار گرفته است و با بهره برداری از این واحدها بخش عمده ای از میعانات گازی تولید شده در داخل کشور به فراورده های میانی و نهایی تبدیل می شوند. پیش بینی می شود تا سال 1400 ظرفیت تولید میعانات گازی در کشور به 1 میلیون و 300 هزار بشکه افزایش پیدا کند. لذا نیاز است یک برنامه ریزی منسجم جهت توسعه صنعت پالایش و پتروشیمی به طور همزمان جهت تولید محصولات با ارزش افزوده بالاتر توسط ذی نفعان مربوطه صورت گیرد.

نفتا

یکی از مهمترین و کلیدی ترین محصولات میانی صنعت پالایش نفت خام، برش نفتا (Naphtha) است. این محصول به عنوان خوراک در واحدهای پتروپالایش از جمله کراکر با بخار، تبدیل کاتالیستی و ایزومریزاسیون مورد استفاده قرار می گیرد. انواع برش نفتا در فرایندهای پالایشگاهی تولید و عرضه می شود.

نفتا شامل هیدروکربن‌های دارای ۵ تا ۱۲ اتم کربن می‌شود که نقطه جوش آنها از ۳۰ تا ۲۰۰ درجه سانتی گراد متغیر است. یعنی اگر نفت خام را از ۳۰ درجه تا ۲۰۰ درجه سانتی گراد حرارت دهیم و بخش جوشیده را جدا کنیم نفتا به دست خواهد آمد. معمولا ۱۵ تا ۳۰ درصد نفت خام در این حرارت به جوش می‌آید در نتیجه همین میزان از نفت خام را می‌توان به طور مستقیم به نفتا تبدیل کرد. اما نفتا در بازار معمولا در دو نوع نفتای سبک (هیدروکربن‌های ۵ و ۶ کربنی) و نفتای سنگین (هیدروکربن‌های ۶ تا ۱۲ کربنی) عرضه می‌شود
همان¬طور که اشاره شد، نفتا به عنوان یکی از مهمترین خوراک های مورد استفاده در صنعت پتروشیمی است. نفتا در پالایشگاه های نفت خام به طور معمول خوراک واحدهای بنزین سازی (Catalytic Reforming) و ایزمریزاسیون می شود تا با تولید ریفورمیت (Reformate) و ایزومریت (Isomerate) در استخر بنزین ممزوج و به عنوان سوخت عرضه گردد. این نکته را نیز باید اشاره کرد که مجتمع های پتروشیمی در فرایندهای پایه، کراکر با بخار (Steam Cracker) و آروماتیک سازی (Catalytic Reforming) اقدام به تولید الفین های سبک (اتیلن،پروپیلن و بوتادین و بوتیلن ها) و آروماتیک ها (بنزن، تولوئن و زایلن) می نمایند که خوراک این واحدها نیز نفتای سبک و سنگین می باشد.
در حال حاضر 9 مجتمع پالایشی کشور به صورت بالفعل و دو پالایشگاه در حال احداث از جمله ستاره خلیج فارس و سیراف پتانسیل عرضه نفتا را دارا می باشند. شایان ذکر است بسیاری از واحدهای گاز و گاز مایع (NGL) کشور نیز نفتای سبک و سنگین تولید و عرضه می نمایند.
مرکز مطالعات زنجیره ارزش معتقد است با توجه به دسترسی به منابع هیدروکربوری سبک و با کیفیت همچون مایعات گازی (NGL)، میعانات گازی (Condensate) و نفت خام سبک، کشور عزیزمان ایران توانمندی تولید نفتای با کیفیت و رقابتی را جهت ارائه به صنعت پتروشیمی برخوردار می باشد تا به کمک فرایندهای کراکر با بخار و تولید آروماتیک اقدام به تولید محصولات پایه و توسعه زنجیره ارزش این محصولات نماید. از طرف دیگر این موضوع را نیز باید یادآوری نمود که زمانی می توان انتظار توسعه پایدار و رقابتی را برای مجتمع ها و طرح های پتروشیمی دانست که ارتباط بین صنعت پالایش و پتروشیمی به صورت سیستماتیک تعریف و حفظ شود.

O. Zadakbar^∗, A. Vatani and K. Karimpour
.Faculty of Chemical Engineering, University College of Engineering, University of Tehran, No. 8 Khoshnevis St
Isargaran St. Valfajr St. Kashani Ave., Postal Code: 1474674784, Tehran-Iran
e-mail: zadakbar@aim.com – avatani@ut.ac.ir – kianoosh_karimpour@yahoo.com
Corresponding author*

Abstract — Flare Gas Recovery in Oil and Gas Refineries —Environmental and economic considerations have increased the use of gas recovery systems. Regarding our comprehensive process evaluation in 11 oil and gas refineries, we devised practical methods to approach zero flaring. This paper presents the results of two case studies of reducing, recovering and reusing flare gases from the Tabriz Petroleum Refinery and Shahid Hashemi-Nejad (Khangiran) Natural Gas Refinery, both in Iran. The design considerations, economics of the process and system operation are studied in this paper. Flare gases are compressed and returned to the fuel gas header for immediate use as fuel gas. Flare gas recovery reduces noise and thermal radiation, operating and maintenance costs, air pollution and emission, and fuel gas and steam consumption. Process stability and flare tip increment without any impact on the existing safety relief system are also the effects of the flare gas recovery system.

INTRODUCTION

Worldwide, final product costs of refinery operations are becoming proportionally more dependent on processing fuel costs, particularly in the current market, where reduced demand results in disruption of the optimum energy network through slack capacity [1]. Therefore, to achieve the most cost-beneficial plant, the recovery of hydrocarbon gases discharged to the flare relief system is vital. Heaters and steam generation fuel provision by flare gas recovery leaves more in fuel processing and thus yield increment. Advantages are also obtained from reduced flaring pollution and extended tip life [1].
During recent years in Iran, all projects have included the collection of associated gases. Thus, flare gas recovery in oil and gas refineries are going to be neglected.
Therefore, in the present work, investigations were made into the operational conditions of 11 important refineries and petrochemical plants. After comprehensive evaluations, we devised practical methods to reduce, recover and reuse flare gases for each petroleum refinery, natural gas refinery and petrochemical plant. The list of refineries and petrochemical plants is shown in Table 1.

1. COMPREHENSIVE PROCESS INVESTIGATION
Adequate process evaluation of plants, especially the units that produce flare gases, comprehensive monitoring of flow and composition of flare gases, investigation of existing flare systems, and finding alternative choices for reusing flare gases were carried out in 11 petroleum refineries, natural gas refineries and petrochemical plants. The results of the investigation of the existing flare systems, finding alternative choices for reusing flare gases and the overall flare gas recovery system are discussed below.

1.1 Investigation into the Existing Flare Systems
Flare tips are exposed to direct flame during their service life, which can of course be quite damaging. As a result, flare tips need to periodically be taken out of service and refurbished, which adds to production costs. The life of a flare tip is related to the amount of usage. Some of the flares were revealed to burn excess gas due to tip damage. By repairing or replacing these tips, purge gas will be reduced. Natural gases are typically used as purge gases. This use of natural gases for twenty-four hours each day is not only wasteful of a precious natural resource, it is also very expensive and can represent an expenditure of many tens of thousands of dollars per year. Since air is caused to enter the flare system from the atmosphere only when there is a decrease in the temperature of the gas contained in the pressure-tight flare system, there is a need for purge or sweep gases only when there is a decrease in the temperature of the internal gas content of the flare system.

For this reason, there is no need for around-the-clock injection of purge gas for the purpose of avoiding entry of air into the flare system. However, to date, there has been no system for automated injection of purge gases into flare systems only as they are needed, due to gas system temperature decrease. Providing a pair of temperature sensors in the flare gas line is an alternative way to decrease purge gases. These two sensors are placed in close proximity. One is a fast-acting sensor, which responds rapidly to any change in temperature. The other is a slow-acting sensor, which responds lowly to a change in temperature.
Thus, in combination, they provide a sensor system sensitive to change in temperature in the flare gas line [2]. To save gas burning, it is recommended to repair or replace pilots with more reliable ones. Also, in some refineries, many ignition systems are fitted, but never in use, because they simply do not work when they are needed. As a result, purge gas is increased to enhance the reliability of the flare. Multi-pilot gas conservation systems are recommended for ignition of waste gas from a flare burner, provisions being made to reduce or limit the pilots for ignition at the most effective location as determined by the wind direction and further, if desired by the wind velocity, a reduction in the number of pilots, effecting substantial savings of combustible gas [3]. A pilotless flare ignitor is an alternative choice too. A pilotless flare ignitor is capable of igniting waste gas issuing continually or sporadically from a flare stack and includes an ignitor housing with an open end which extends into the flare stack.
In some areas a large number of flare stacks have been installed. Global studies recommended optimizing the existing number of flares [4].
In some areas the maximum design capacity of the equipment was reached. Hence, surplus gas is being flared. The studies identified equipment that can be debottlenecked; otherwise, additional new units need to be installed [4].

1.2 Finding Local Alternative Choices for Reducing and Reusing Flare Gases
Some storage tanks are fixed roof types that require positive pressure set at a certain point. The tank is directly connected to a flare. One of the studies recommended a flow suction tank gas recovery system to be installed at each fixed roof storage tank. The vapor jet system is an alternative to conventional vapor recovery technology for the recovery of hydrocarbon vapors from oil production facilities’ storage tanks. The process utilizes a pump to pressurize a stream of produced water to serve as the operating medium for a jet pump [1].
In particular, the refinery off gases from a FCCU contain olefin components, up to about 20 percent by volume ethylene and up to about 11 percent by volume propylene, which components normally are not recovered from the off gases, but which components may have value to warrant recovery and use in other petrochemical processes or uses in downstream processing [1].
Delayed coking operations increase the volume of byproduct non-condensable hydrocarbons generated and typically flared. A local flare gas recovery system on a delayed cocker unit is capable of recovering a huge amount of flare gases from the delayed cocker [5].
Using some new environmentally friendly technologies reduces flare emissions and the loss of salable liquid petroleum products to the fuel gas system. New waste heat refrigeration units are useful for using low temperature waste heat to achieve sub-zero refrigeration temperatures with the capability of dual temperature loads in a refinery setting. These systems are applied to the refinery’s fuel gas makeup streams to condense salable liquid hydrocarbon products [6].

1.3 Flare Gas Recovery System
Environmental and economic considerations have increased the use of gas recovery systems to reclaim gases from vent header systems for other uses. Typically, the gas is recovered from a vent header feeding a flare. Depending on vent gas composition, the recovered gas may be recycled back into the process for its material value or used as fuel gas. Vent gas recovery systems are commonly used in refineries to recover flammable gas for reuse as fuel for process heaters [1]. The Tabriz petroleum refinery and Shahid Hashemi-Nejad (Khangiran) gas refinery are the most important parts of our work. The results of these case studies are discussed.

1.3.1 Flare Gas Recovery for the Tabriz Petroleum Refinery
The Tabriz petroleum refinery consists of 14 refining units and 10 units related to other services. The nominal capacity of the Tabriz refinery is 80000 barrels per day, but by executing the authorities’ augmenting schemes, nominal capacity has been increased to 115000 barrels per day. The crude oil, up to 115000 barrels in a day, is brought from crude oil preserving tanks to a distillation unit in order to be separated into oil cuts. The necessary crude oil is supplied from the Ahwaz oil fields via a 16-inch pipeline. The Tabriz petroleum refinery normally burns off 630 kg/h gas in flare stacks [7]. The average quantity and quality of flare gas are shown in Table 2.

Having investigated the operational conditions of the Tabriz petroleum refinery, especially the units which produced flare gases, we proposed practical methods to reduce, recover and reuse flare gases for the Tabriz petroleum refinery.
There are some alternative choices for using recovered gases. The most important choices are: using flare gases as fuel gas, for electricity generation and as feed gas. In the next step, we tried to find the best choice for using recovered flare gases. Regarding the operational and economic evaluation, recovery of hydrocarbon gases discharged to the flare relief system is probably the most cost-beneficial plant retrofit available to the refinery. Use of flare gases to provide fuel for process heaters and steam generation leaves more in fuel processing, thus increasing yields. Regarding the results of data analyses, the mean value of molecular weight of the gas is 19.9, and the flow discharge rate is modulated between 0 and a maximum of 800 kg/h. The average temperature is 80◦C and the average pressure is 1 bar.

1.3.2 Flare Gas Recovery for the Shahid Hashemi-Nejad (Khangiran) Gas Refinery
The Shahid Hashemi-Nejad (Khangiran) is one of the most important gas refineries in Iran. The necessary natural gas is supplied from the Mozdouran gas fields. The Shahid Hashemi-Nejad (Khangiran) Gas Company consists of 5 sour gas refineries, 3 dehydration units, 3 sulfur recovery units, 2 distillation units, 2 stabilizer units and 14 additional units related to other services. The Shahid Hashemi-Nejad (Khangiran) gas refinery normally burns off 25000 m3/h gas in flare stacks [8]. The analysis of operational conditions shows that some units normally produce flare gases more than other units. The compositions of flare gases produced by these units are shown in Table 3. These streams make the main flare stream. In addition, the process specifications of flare gases in the Shahid Hashemi-Nejad (Khangiran) gas refinery are shown in Table 4.

After a comprehensive process evaluation, we devised practical methods to reduce, recover and reuse flare gases for the Shahid Hashemi-Nejad (Khangiran) gas refinery. In addition, the flame igniter system, the flame safeguards and the existing flare tip have to be replaced.
The fuel gas of the Shahid Hashemi-Nejad (Khangiran) gas refinery is supplied by sweet gas treated in the gas treating unit (GTU). Due to a pressure drop in the gas distribution network in Mashhad city in the northeast of Iran, during cold seasons, they encourage using flare gases as an alternative fuel gas resource and eliminating the use of sweet gas produced in a GTU. Regarding the Shahid Hashemi-Nejad (Khangiran) gas refinery recommendations and the operational evaluations, recovery of hydrocarbon gases discharged to the flare relief system is probably the most cost-beneficial plant retrofit available to the refinery.

2. FGRS DESIGN
2.1 Flare Gas Design for the Tabriz Petroleum Refinery
The design considerations include: the flare relief operation and liquid seal drum, the flow and composition of flare gases and the refinery fuel system. The considerations led to a unit design for normal capacity up to 630 kg/h. Our proposed flare gas recovery system is a skid-mounted package which is located downstream of the knockout drum, as all flare gases from various units in the refinery are available at this single point. It is located upstream of the liquid seal drum as pressure control at the suction to the compressor will be maintained precisely, by keeping the height of the water column in the drum. The compressor selection and design depends on the system capacity and turndown capability [9]. The most appropriate type and number of
compressors for the application are selected during the design phase of the project. Liquid ring compressor technology is commonly used because of its rugged construction and resistance to liquid slugs and dirty gas fouling [1]. A number of characteristics which must be taken into account when compressing flare gas are as follows:
The amount of gas is not constant, the composition of the gas varies over a wide range, the gas contains components which condense during compression, and the gas contains corrosive components [10].
A modular design which includes two separate and parallel trains capable of handling various gas loads and compositions is recommended for the Tabriz petroleum refinery.
The recommended system consists of compressors which take suction from the flare gas header upstream of the liquid seal drum, compress the gas and cool it for reuse in the refinery fuel gas system. It includes two LR compressors, two horizontal 3-phase separators, two water coolers, piping and instruments. The compressed gas is routed to the amine treatment system for H2S removal. The effect of the devised FGRS on flaring in Tabriz petroleum refinery is shown in Figure 1.
The FGR system with LR compressor for the Tabriz petroleum refinery is shown in Figure 2.

2.2 Flare Gas Design for the Shahid Hashemi-Nejad (Khangiran) Gas Refinery
In this case, the considerations led to a unit design for normal capacity up to 25000 m3/h. The process specifications
of the outlet must be similar to refinery fuel gas. The proposed flare gas recovery system is like the proposed system for the Tabriz petroleum refinery. It has a modular design and comprises three separate and parallel trains capable of handling various gas loads and compositions.

3. SAFETY AND CONTROL
The principal potential safety risk involved in integrating a flare gas recovery system is from ingression of air into the flare header, which can be induced by the compressor suction. This could result in a flammable gas mixture being flashed off inside the system from flare pilots [4]. It should be noted that the FGR unit does not interrupt the flare system and should be able to handle sudden increases in load. Therefore, no modification to the existing flare system will be attempted, but with two exceptions. The connections through which the compressors will take suction on the system, and additional seal drums which will provide extra safety against air leakage into the flare system and allow the buildup of flare header pressure, during compressor shutdown or flare gas overload. Also, the compressor control system does not affect the flare system pressure and thus its design will be able to avoid low pressure suction in the flare system during normal operation. When the compressors are not functioning properly, automatic or manual shutdown should result. The flare system will operate as it does now with no compressors. Meanwhile, if the volume of flare gases relieved into the flare system exceeds the capacity of the FGR unit, the excess gases will flow to the flare stack.
If this volume is less than the full capacity of the FGR unit, a spillback valve will divert the discharged gases back to the suction zone to keep the capacity of the flare gas recovery unit constant.
Other safeguards to the flare system against air leakage are [4]:

4. ECONOMICS AND EMISSION CONTROL
In this section, the results of economic evaluations and the results of emission control are presented. These results were obtained based on 0.11 $/m3 for fuel gas, 6 $/ton for steam and 5 cent/kWh for electricity.

4.1 Economic Evaluations for the Tabriz Petroleum Refinery
The recommended system includes two LR compressors, two horizontal 3-phase separators, two water coolers, piping and instruments. Capital investment to install the FGR system is $0.7 million which, including maintenance, amortization and taxes, corresponds to a payback period of approximately 20 months. Another essential effect of using the FGRS is gas emission reduction. By using the FGRS in the Tabriz petroleum refinery, we can decrease up to 85% of the gas emission including CO2, CO, NOx, SOx, etc.

4.2 Economic Evaluations for the Shahid Hashemi-Nejad (Khangiran) Gas Refinery
The proposed system for the Shahid Hashemi-Nejad (Khangiran) gas refinery has three LR compressors, three horizontal 3-phase separators, three water coolers, piping and instruments. Capital investment to install the FGR system is $1.4 million, which includes maintenance, amortization and taxes, with a payback period of approximately 4 months. We can decrease up to 70% of the gas emission by using the FGRS in the Shahid Hashemi-Nejad (Khangiran) gas refinery.

CONCLUSION
It is well known that there are many economical ways to achieve flaring minimization and gas conservation in oil and gas refineries. In order to find these ways, a comprehensive process evaluation of plants, especially units that produce flare gases, comprehensive monitoring of flow and composition of flare gases, investigation of existing flare systems and finding alternative choices for reusing flare gases was carried out in 11 petroleum refineries, natural gas refineries and petrochemical plants. Based on our comprehensive process evaluation, we devised alternatives to reduce gas flaring.
Recovery of hydrocarbon gases discharged to the flare relief system is probably the most cost-beneficial plant retrofit available to the Shahid Hashemi-Nejad (Khangiran) gas refinery and the Tabriz petroleum refinery. Use of flare gas to provide fuel for process heaters and steam generation leaves more in fuel processing, thus increasing yields. Advantages are also obtained from reduced flaring pollution and extended tip life. In the Tabriz petroleum refinery, 630 kg/h flare gas will be used as fuel gas by $0.7 million capital investment corresponds to a payback period of approximately 20 months, and also 85% of gas emissions will be decreased. In the Shahid Hashemi-Nejad (Khangiran) gas recovery, 25000 m3/h flare gas will be used as fuel gas by $1.4 million capital investment corresponds to a payback period of approximately 4 months, and 70% of gas emissions will be decreased.

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