Hydrocarbon Dew Point Research Articles

Heavy hydrocarbon recovery with integration of turboexpander and JT valve from highly CO2-containing natural gas for gas transmission pipeline

Demand of natural gas is predicted to increase since many valuable products can be produced. Water and heavy hydrocarbon content are the key for gas pipeline facility. To meet requirement of natural gas transportation, dehydration unit (DHU) and hydrocarbon dew point control unit (DPCU) are necessary to avoid water and hydrocarbon condensation during transmission. The conventional dehydration technology, TEG contactor, can lower water content from 1,304 mg/m3 to 80.35 mg/m3 where the maximum limit of water content in natural gas is 97 mg/m3 to prevent hydrate formation. DPCU is installed to remove heavy hydrocarbon, especially C5+. Integration of JT valve and turboexpander was employed to obtain the low gas dew point. The hot gas stream that entered the JT valve was observed. The lower hot bypass gas was applied, the lower hydrocarbon dew point and the more condensate flowrate was achieved. The highest power generation can be gained at low hot gas flow ratio which also influenced the exit pressure and temperature of compressor. In pipeline simulation, the pressure and temperature drop occurred at the high hot gas rate. To examine the arrival condition, dew point curves were generated and showed that the limitation of hot gas flow ratio has to be below 0.6 to prevent heavy hydrocarbon condensation in pipeline.

Examination of Condensation Liquid Formation in Istanbul Natural Gas Distribution Network

In this study, the formation of natural gas liquid in gas distribution lines, particularly at regional stations, service boxes, customer installations, and gas meters, was investigated. The study aims to address the problems associated with natural gas liquid formation, such as interruption of supply and decreased efficiency of combustion devices. The indirect measurement of the hydrocarbon dew point was analyzed using C6+ chromatograph data, and the model based on directly measured C6+ data were converted into C6/C7/C8 data by four different methods. As distinct from studies in the literature, this study experimentally determines the distribution of heavy hydrocarbons from C9 to C19 based on indirect methods for acquiring C8+ data and direct measurement of C6+ data. The hydrocarbon dew point temperature was calculated using the Peng–Robinson (PR) and Soave–Redlich–Kwong (SRK) equations of state. The results of the analysis performed on two city gate stations showed that the critical temperatures were 4.21 °C at a pressure of 10.81 bar and 8.27 °C at a pressure of 11.25 bar, respectively. These values were obtained from a model designed to determine the dew point temperature in the area where natural gas liquid formation was most prevalent. The experimental analysis and indirect measurements indicated the occurrence of a two-phase gas–liquid formation.

A novel strategy for process optimization of a natural gas liquid recovery unit by replacing Joule–Thomson valve with supersonic separator

The natural gas liquid recovery is an important process in a gas plant to correct hydrocarbon dew point and earn profit. In this study, a natural gas liquid recovery unit operated based on the Joule–Thomson process was investigated and its performance was optimized. To improve the system performance, the plant configuration and intermediate pressure ratio were defined as the variables and maximization of the natural gas liquid recovery rate and maximization of exergy efficiency were defined as the objective functions. To improve the plant performance, the amount of natural gas liquid recovery rate should be increased. To achieve this goal, several scenarios for the intermediate pressure ratio and three new configurations were proposed for the investigated gas plant. In the proposed configurations, the supersonic separators with optimized structures were used instead of the Joule–Thomson process. It was observed that all three proposed configurations improved the natural gas liquid recovery rate compared to the existing configuration. For example, by installing two supersonic separators instead of second and third stage Joule–Thomson valve + low temperature separator, at the optimal operating condition, the natural gas liquid recovery rate increased about 390%. The influence of the intermediate pressure ratio on the phase envelope diagram, exergy efficiency, dew point depression and natural gas liquid recovery rate was also investigated. By comparing the influence of intermediate pressure ratio and modifying the plant configuration on the objective functions, it was observed that the system performance can be further improved by modifying the plant configuration.

Modeling and Investigation of an Industrial Dehydration and Hydrocarbon-Removal Process by Temperature Swing Adsorption

In this study, a water- and heavy hydrocarbon-removal process of a natural gas refinery currently in operation using the temperature swing adsorption method is modeled and investigated. The aim of this process is to decrease the hydrocarbon dew point to −10 °C and diminish the water content of the gas to about 0.1 ppm. This unit consists of four beds with two layers in which two beds are in the adsorption state, while the others are kept in the regeneration state. The gas composition and the bed specification are obtained from the available data from the refinery. The Ergun equation is considered for the pressure drop calculation. The results show that the developed model can predict the outputs with good accuracy. Sensitivity analysis of operating condition parameters such as temperature, pressure, and regeneration gas flowrate are carried out. Analysis of the regeneration temperature proved that temperature reduction from 268 °C to 210 °C can improve recovery of the heavy components. In addition, the regeneration gas flow rate can be reduced to about 0.4 kmole·s−1 as an optimum value. Moreover, 303 to 310 °C is the optimum range for the feed temperature. Due to the presence of the air cooler in the upstream process, and according to the ambient air temperature, feed temperature can be decreased to obtain better results.

Controlling hydrocarbon dew point and water dew point of natural gas using Aspen HYSYS

A great attention is subjected to the environmentally friendly natural gas. Compared to other fossil fuels, natural gas is a cleaner burning due to the lower emission of carbon dioxides into the air. Removal of associated hydrocarbons from natural gas streams plays an important role to sell and to achieve the pipeline specification of natural gas. To satisfy the specification of pipelines, the hydrocarbon dew point and water dew point of natural gas must be controlled below the pipeline operating conditions to prevent many problems: two-phase flow and hydrate formation in the system. The main purpose of this paper is to simulate the gas plant process to study the effect of natural gas composition and changing in differential pressure of Joule–Thomson expansion valve on the obtained values of hydrocarbon, water dew points, and cricondentherm temperature.The results of process simulation using Aspen HYSYS have shown that the control of hydrocarbon dew point, water dew point, and cricondentherm of natural gas is achieved through increasing the Joule-Thomson valve differential pressure. There is an inverse relation between increasing Joule-Thomson valve differential pressure (∆p) and hydrocarbon dew point, water dew point, and cricondentherm to meet the specification of gas pipeline transmission. Increasing differential pressure (∆p) from 14 bar to 24 bar causes a decrease in hydrocarbon dew point, water dew point from −1 to −26°C and from 0 to −18°C, respectively. Cricondentherm is also decreased from 4 to −12°C by increasing differential pressure (∆p) from 14 to 24 bars. The operating conditions at differential pressure below 14 bar is not advisable because cricondentherm temperature does not meet the specification of gas pipeline transmission and hence lead to many problems. Careful adjustment of the operating conditions of gas processing plant is very important by making such simulations to choose the optimum operating conditions which meet gas pipeline transmission.

Sustainable offshore natural gas processing with thermodynamic gas-hydrate inhibitor reclamation: Supersonic separation affords carbon capture

Dew-point adjustments and reclamation of thermodynamic gas-hydrate inhibitors injected in subsea flowlines are common operations in offshore natural gas rigs characterized by high costs, power consumption and carbon emissions. Typically, offshore plants employ triethylene-glycol absorption for water dew-point adjustment and Joule–Thomson expansion for hydrocarbon dew-point adjustment, while hydrate inhibitor reclamation is applied only on aqueous-inhibitor streams for re-concentration. To implement economically sustained post-combustion carbon capture on offshore rigs, a more efficient gas processing is necessary. This work contemplates a new process – supersonic separator inhibitor-reclamation – which recovers inhibitors from saturated raw-gas via supersonic separation with liquid-water injection additionally yielding exportable liquefied-petroleum-gas and natural gas with adjusted dew-points. This process dramatically improves profitability for thermodynamic inhibitors methanol, ethanol and monoethylene-glycol, creating an economic leverage that affords a post-combustion capture plant avoiding about 43% of carbon emissions. Even including post-combustion capture penalties, the supersonic separator inhibitor-reclamation process achieves a higher net value than the conventional gas processing without carbon capture. A multi-criteria sustainability assessment, based on quantitative metrics and qualitative aspects over all sustainability dimensions, evinces the supersonic separator inhibitor-reclamation process with carbon capture as more sustainable than the conventional counterpart for all inhibitors, whereas among the three inhibitors, the gas processing with monoethylene-glycol was ranked as the more sustainable for offshore rigs.

Oiling low temperature separation process for dehydration and de-hydrocarbon of natural gas and practical application

In order to reach the specification of water and hydrocarbon dew point, most of the water and C3 and heavier hydrocarbons need to be removed from natural gas. Low Temperature Separation (LTS) process by throttling expansion or refrigeration is commonly employed for natural gas dehydration and de-hydrocarbon as the most economical method. In case of some special natural gas which contains small quantity of the wax (mainly C16+ components), wax is easily deposited in the throttling facilities that leads the blockage of internals of low temperature separator and affects safety operation. Oiling LTS process, a novel process for this kind of special natural gas, is investigated in this work. The oil is injected into the natural gas to reduce the wax precipitation temperature and thus to avoid wax blockage. It is a kind of improvement and innovation process based on conventional treatment ones. According to the simulation analysis and practical application for a natural gas processing plant in Aksu, China, the new process presents good performance. Also, it is found that the best injection point is at the inlet pipe of raw gas pre-cooler and the optimal injecting stream is from the three-phase separator. Also, the injection oil flowrate is determined by refrigerating temperature and the concentration of wax. Meanwhile, the detailed economic analysis of oiling LTS process was involved. Comparing the conventional process, its adding investment is around 423,583$ accounting on 5% total capital cost of this unit. However, from the comprehensive aspects, this optimized process presents a good economic benefit.

Comparison of Natural Gas Hydrocarbon Dewpointing Control Methods

Natural gas dew point is a very important quality parameter. It is specified in predetermined mandatory specifications for the producers through transmission and distribution companies to market. Several problems in gas transmission lines may be caused by the hydrocarbon liquid dropout. These include increase in pressure drop, line capacity reduction, and equipment problems (e.g. compressor damage). Avoiding liquid dropout, the operating current specifications of gas transmission lines require to be operated above the dew point of hydrocarbon (DPH) or cricondentherm hydrocarbon dew point (CHDP). This paper compares the different methods for natural gas hydrocarbon dew-pointing that are widely applied in industry and choose the best method for a gas project to achieve the required hydrocarbon dew point of the export gas. These methods are Joule-Thomson expansion (J-T), turbo expansion, mechanical refrigeration, Pressure Swing Adsorption (PSA) and thermally Regenerated Adsorption (TSA). The comparison was made to choose the best applicable method needed for a gas project to achieve the required export gas specifications. It was found that the mechanical refrigeration method is preferred due to its numerous advantages.

Upgrading exergy utilization and sustainability via supersonic separators: Offshore processing of carbonated natural gas

Offshore processing of natural gas with 44%mol carbon dioxide at remote deep-water oil-and-gas fields is invariably characterized by low-efficiency power generation via gas-fired turbines releasing hot flue-gas and entailing high degradation of resources, high carbon emissions and low sustainability. This work demonstrates how to upgrade exergy utilization and consequently process sustainability by using supersonic separators in some gas processing steps; namely: (i) water dew-point adjustment; (ii) hydrocarbon dew-point adjustment; and (iii) carbon dioxide abatement to 20%mol. To accomplish this, the exergy performance of two supersonic separator gas processing alternatives are compared with conventional gas processing comprising triethylene-glycol absorption for water dew-point adjustment, Joule-Thomson expansion hydrocarbon dew-point adjustment and membrane-permeation carbon dioxide removal. Since exergy is measured relatively to a reference environmental reservoir, two such reference reservoirs are used: RER-1: standard atmosphere with 2%mol water containing hydrocarbons at combustion chemical equilibrium with air species; and RER-2: 1atm water-saturated raw natural gas in equilibrium with liquid water. Aspen-HYSYS simulations are used to solve mass/energy balances and thermodynamic property calculations. With RER-2 the conventional gas processing conserves 63.3% of the inlet exergy, while the two alternative supersonic separator processes attain 66.5% and 72.4% of exergy conservation, proving the associate gains of exergy efficiency and sustainability.

Discussion on Water Dew Point and Hydrocarbon Dew Point of Natural Gas

During natural gas processing and gathering and transportation, water dew point and hydrocarbon dew point as two of control parameters in natural gas because of safety, economy and efficiency etc. In the field chilled mirror manual visual method always be taken to measure water and hydrocarbon dew point due to online instrument test under a differential condition from the pipeline. For hydrocarbon dew point, there’re some assays have implied that heavier components in natural gas have an important effect on hydrocarbon dew point, at the same time hydrocarbon dew point gained under the pressure between 2MPa~4MPa is equal to the max condensation temperature which has a practical meaning. On the other hand, the retrograde condensation cannot be ignored; for water dew point, application of molecular sieve would make dew point measurement easier, while application of dehydrating agents such as methanol; glycols and glycerol could cause interference, instruments &operators differences are exist, but the changing process is consistent when chilled down temperature. In this case, Attention should be given to a white fog which might appear on the center of the surface of the chilled mirror one or more times while temperature dropping down. At last some suggestions are given from two aspects of processing and measurement of water and hydrocarbon dew point.

Hydrocarbon simulation behavior of wet natural gas reservoirs

Knowing hydrocarbon dew point conditions in natural gas (HCDP) are becoming widely important in the modern marketing of liquid and gas. Without determination dew point conditions (Pressure & Temperature), the accurate description of phase changes and phase behavior cannot be achieved. Numerous models for only predicting dew point pressure of gas condensate have been proposed and other for wet natural gas reservoirs, but there is no model for predicting both dew point pressure(DPp) and dew point temperature (DPT) for wet natural gas reservoirs. Some of the published models assume knowledge the reservoir fluid composition (requiring laboratory experiments to be performed), while others only require field parameters such as reservoir temperature, stock-tank oil API, and the condensate-gas ratio (CGR). The primary objectives of this paper are to determine dew point temperature (DPT) and dew point pressure (DPp) correlations using a fluid database of nearly fifty-six wet natural gas reservoirs, that is very important for engineers to understand and manag wet natural gas reservoirs. This model was made using multiple least-square nonlinear regression analysis methods to find hydrocarbon dew point conditions (HCDP) as a function of [CGR, Tr, API gravity, γw, γC7+, MWw and C1, C2, CO2, N2 mole %] with a different constant value. Both statistical and graphical accuracy ensures that new models are more accurate in predicting hydrocarbon dew point conditions (HCDP) in comparison with equations of state by using limited data. Finally, thirty-four new separate set of measured data were used in testing models with the excellent agreement as compared with laboratory works.

Hydrocarbon Dew Point Measurement and Model Evaluation of Synthetic and Real Natural Gases.

Hydrocarbon dew point (HCDP) is one of the most important quality specifications of natural gas. Measuring and predicting the HCDP accurately are essential for the natural gas industry. However, the comprehensive experimental HCDP curve data are still rare, and knowledge about adopting proper prediction models remains unclear. In view of this, HCDP determination work by use of an improved test system and model evaluation based on more than 1000 dew points data have been done to improve the aforementioned dilemma. HCDP curve data of three gravimetrically prepared synthetic natural gases (SNGs) and one real gas (RG) are determined first. Then, one set of data containing 712 dew points from 28 SNGs and 334 dew points from 14 RGs is used to evaluate the performance of eight different HCDP prediction models including Soave–Redlich–Kwong (SRK), SRK–Twu, Peng–Robinson (PR), Twu–Sim–Tassone (TST), predictive SRK (PSRK), GERG-2008, PSRK, and perturbed-chain statistical associating fluid theory (PC-SAFT) models. Considerable prediction deviation of these models in the high-pressure region (pressure above 6.0 MPa) is observed compared to that in the low-pressure region (under 6.0 MPa), and the reasons for that difference are discussed. Evaluation results reveal that among the eight prediction models, GERG-2008 has the best performance (overall average absolute deviation (AAD): 1.44 °C) for SNGs, and PSRK and SRK–Twu fits the experimental data best for RGs (overall AAD: 2.50 °C). Therefore, GERG-2008 is recommended for HCDP prediction of relatively lean gas, whereas PSRK and SRK–Twu are recommended for calculating the HCDP of relatively heavy natural gases in low-pressure and high-pressure regions, respectively.

Protected supersonic separator performance against variable CO2 content on natural gas processing: Energy and sustainability analyses

In offshore oil-and-gas fields with high CO2 content, oil-and-gas processing entails recycling CO2 to the field for enhanced oil recovery. Despite blocking fossil CO2 ingress into the biosphere and improving oil production, this entails increasing %CO2 in oil-and-gas with time, challenging the processing plant. Supersonic separator is a compact gas processing solution that can simultaneously adjust water and hydrocarbon dew-points. But, supersonic nozzles can only work if sonic-throat flow occurs. In this work a supersonic nozzle sized to a high-pressure 25%mol CO2 feed is submitted to varying %CO2 from 5%mol to 80%mol under constant feed temperature/pressure and molar flow rate. Varying %CO2 affects nozzle performance with three possible outcomes: (i) feed is insufficient to reach sonic-throat flow, entailing no supersonic processing; (ii) feed is at design condition (25%mol CO2) and nozzle works tightly; and (iii) sonic-throat flow is achieved with a fraction of the feed; i.e., there is no room to process the rest. These apparent shortcomings of supersonic gas processing are examined and a control-scheme based on manipulating feed-pressure is proposed to circumvent feed deficit/excess. With the proposed feed-pressure adjustment to protect supersonic separator operation, energy and sustainability assessments are conducted to evaluate environmental and gas-fired power generation impacts from the supersonic processing of feeds with varying %CO2. Feeds with 10%mol/15%mol/20%mol CO2 have highest sustainability-degrees.

Offshore Natural Gas Conditioning and Recovery of Methanol as Hydrate Inhibitor with Supersonic Separators: Increasing Energy Efficiency with Lower CO<sub>2</sub> Emissions

The oil and gas industry represents an important contributor to CO2 emissions as offshore platforms are power intensive for producing, processing and transporting hydrocarbons. In offshore rigs CO2 emissions mainly come from on-site gas-fired power generation for heat and electricity production. The accumulation of atmospheric CO2 is one of the main causes of the planetary greenhouse effect, thus CO2 emissions should be minimized. To achieve that, more energy efficient processes for natural gas (NG) conditioning are needed in order to minimize platform power consumption and thus lowering the associated generation of CO2. In addition, in offshore scenarios gas-hydrate obstructions are a major concern in flow assurance strategies, since thermodynamic conditions favoring hydrate formation are present, such as high pressure, low external temperature and gas contact with free water. To avoid hydrate issues, hydrate inhibition is carried out by the injection of a thermodynamic hydrate inhibitor (THI) in well-heads such that it flows along with production fluids, thus removing the thermodynamic conditions for hydrate formation and ensuring unimpeded flow. Therefore, the three-phase high-pressure separator (HPS) is fed with production fluids, where the HPS splits the feed into: (i) an upper gas phase, (ii) hydrocarbon condensate, and (iii) a bottom aqueous phase. The gas phase goes to NG conditioning for hydrocarbon dew point adjustment (HCDPA) and water dew point adjustment (WDPA) so as to make NG exportable. The hydrocarbon condensate (if present) is collected for stabilization and the bottom aqueous phase consisting of water, salts and THI is sent to a THI recovery unit (THI-RU) for THI re-concentration and reinjection. In conventional plants, WDPA and HCDPA are done by glycol absorption and Joule-Thomson expansion respectively. Moreover, the HPS gas carries some THI such as methanol that is lost in the processing. This work analyses a new process – SS-THI-Recovery – where HPS gas feeds a supersonic separator (SS) with injected water and compares it to the conventional processing. As a result, SS ejects a cold two-phase condensate with almost all water, THI and C3+ hydrocarbons, discharging exportable NG with enough HCDPA and WDPA grades, while the condensate gives aqueous THI returned to the THI-RU and LPG with high commercial value. Thus, SS-THI-Recovery not only avoids THI losses as well as exports NG and LPG. Both conventional gas plant and SS-THI-Recovery alternative coupled to THI-RU were simulated in HYSYS 8.8 for a given NG field and targeting the same product specifications. SS-THI-Recovery presented lower power consumption and thus less associated CO2 emissions, while potentially increasing the gas plant profitability, as THI losses are significantly reduced and higher flow rate of LPG with higher commercial value is produced in comparison with the conventional alternative. Hence, the higher efficiency of SS-THI-recovery makes it not only more environmentally friendly with lower CO2 emissions, but also a potential alternative for improving process economics and thus providing an economic leverage that could justify investments in carbon capture technologies, contributing to avoid CO2 emissions even more with cleaner NG and LPG production.

Supersonic separator for cleaner offshore processing of supercritical fluid with ultra-high carbon dioxide content: Economic and environmental evaluation

Offshore gas processing presents challenges, especially when high flow rates, high-pressure and high carbon dioxide contents are involved. The present scenario comprehends offshore processing of high flow rate of high-pressure natural gas with 68%mol carbon dioxide, which results from oil production and behaves as a dense supercritical fluid. The processing goals with this fluid comprise: [A] water dew-point adjustment; [B] hydrocarbon dew-point adjustment; [C] decarbonation of a small part to 20%mol carbon dioxide fuel-gas for power production; and [D] compression/pumping of the remaining fluid enriched with carbon dioxide from decarbonation for enhanced oil recovery. For these tasks the industry considers traditional well established processes such as molecular-sieves adsorption for water dew-point adjustment, Joule-Thompson expansion for hydrocarbon dew-point adjustment and membrane-permeation for carbon dioxide removal. However, conventional technologies can become cumbersome in such awkward conditions. Thus, unconventional solutions are sought for reliability, lower equipment size/weight, and better power consumption, emissions and environmental sustainability. Recently, supersonic separators have been analyzed in proof-of-concept researches for natural gas processing. In this regard, this work quantitatively proves that goals [A],[B],[C] are achievable using only supersonic separators, attaining 33% higher net value, 40% greater oil production, 10% lower investment and economic leverage to reach lower carbon emission relatively to conventional counterparts.

Supersonic separator for cleaner offshore processing of natural gas with high carbon dioxide content: Environmental and economic assessments

Supersonic separators offer a cleaner offshore processing of natural gas with carbon dioxide content from deep-water oil-gas fields. Conventional offshore gas processing comprises water dew-point adjustment via glycol-absorption, hydrocarbon dew-point adjustment via Joule-Thomson expansion, and carbon dioxide removal via membrane-permeation. Alternative processing contemplates the use of supersonic separators for adjusting gas dew-points followed by carbon dioxide capture via membrane-permeation (so-called SS-MP scheme); or for adjusting gas dew-points and also accomplishing carbon dioxide abatement (so-called SS-SS scheme). The conventional process is environmentally and economically compared with SS-MP and SS-SS for application in offshore rigs treating raw gas (44%mol carbon dioxide) to produce exportable fuel-gas (≈20%mol carbon dioxide), while dispatching carbon dioxide rich fluid (≈75%mol carbon dioxide) for enhanced oil recovery in the oil-gas field. Results show that SS-MP requires 7.8% less power than the conventional process. Moreover, implementing SS-SS deepens the advantage against the conventional operation because SS-SS produces carbon dioxide rich fluid at high-pressure, requiring much less compression power for enhanced oil recovery than the low-pressure permeate from membrane-permeation. SS-SS has lowest carbon emission (−28.3%), lowest power consumption (−21.3%) and best economic performance: lowest manufacturing cost and lowest compressor investment. Thus, SS-SS is the overall best and cleanest solution, with highest 20 years net value (+860 MMUSD) and lowest environmental impact.

Performance of Equation-of-State for Hydrocarbon Dew Point Control in Gas Flow-line in a Nigerian Field

Associated gas in a flow-line in a Nigerian field was suspected to be accountable for unaccounted-for gas in the flow-station. Gas molecular compositions of Low Pressure suction gas and Injection Discharge gas for operating conditions of pressure and temperature from the field were analysed by the use of Soave-Redlich Kwong and Peng-Robinson Equations of State with PVTp thermodynamic software. The phase envelope predicted the Hydrocarbon dew point(s) observable from the dew point curve, and the operating conditions of 116 o F for LP suction gas and 112.8 o F for Injection Discharge gas were observed to be outside of the dew point curve, and greater than the cricondentherm of 69.2 o F and 66.6 o F for SRK EOS and 65.6 o F and 63.0 o F for PR EOS respectively as predicted by the PVTp. The conditions made it impossible for hydrocarbon liquid dropout, hence, could not account for the gas. Hydrate formation was also prevented as observed from the hydrate curve. Keywords: Cricondentherm, Dew Point System, Equation of State, Natural gas

ENERGY EFFICIENT USAGE OF NATURAL GAS CRITERIAS

The article suggests that Wobbe Index is one of the main criteria when determining quality of natural gas for natural gas Interchangeability from different sources ДСТУ ISO:13686:2016. For effective natural gas combustion the Wobbe Index Ws gas of should not differ form Ws of gas G20 by more than 2 percent. Especially in cases where equipment designed precisely to work with G20 gas. In that case it is necessary to adjust gas pressure or substitute machine design for different gas usage. Methane number that is corrected by Wobbe Index could be another criteria of quality of gas determination. Authors suggest minimal methane number of MN=65 defined by EN 16726:2015 is not sufficient. It is proven that even in case of higher combustion energy output for gas with Wobbe Index significantly lower of G20 gas test values the overall efficiency of using this gas in particular burner system is much lower. Flame flow for natural gas in streams M166 and M208 is closer to wrinkles due to chemical mixture of gas and natural gas in M1204 stream creates yellow tipping due to incomplete combustion, sulfur content similar to G21 test gas. With mediocre combustion energy output same burners consume more natural gas to provide same amount of energy. Natural gas from stream M404 has almost ideal mixture of components. Its Wobbe Index is 50,41 MJ/Nm3 but hydrocarbon dew point of 15.3 °C at P=3.92 MPa. That indicates relative humidity of 100%. Specific humidity of gas in stream is 0.44 grams per cubic meter that is dangerous for creating natural gas hydrates, solid clathrate compounds that may damage machinery or obstruct pipeline flow. Authors suggest to provide certain set of actions to process natural gas into so called clean “pipeline quality dry gas” at wells or gas-processing plants to improve gas parameters to be closer to European Union standards. As for government policies they have to be reworked from using “energy saving” term to “energy efficiency” term and start improving on efficient usage of natural gas by approving and applying newest energy efficient technologies and machinery into gas transport\consumer network.

Carbon capture and high-capacity supercritical fluid processing with supersonic separator: Natural gas with ultra-high CO2 content

Some deep-water offshore fields produce oil with high gas/oil ratios and ultra-high %CO2 (>60%mol) with the onus of processing low-grade gas simultaneously handling huge CO2 dispatch goals. Thus, processing solutions are needed to make feasible such high-capacity gas rigs hundreds of kilometers offshore. Feasibility relies on the choices for CO2 capture and adjustment of water and hydrocarbon dew-points of such high flow rate gas. This problem was approached adopting supersonic separators for dew-point adjustments and for CO2 capture on a floating-hub processing 50 MMsm³/d of CO2 ultra-rich gas, reinjecting 96% of treated CO2-rich gas for enhanced oil recovery, while reserving 4% as fuel-gas after CO2 abatement to 20%mol for power production. Process alternatives were assessed in terms of power demand and profitability comparing supersonic separator with membrane-permeation for CO2 removal. Results show that 1st supersonic separator for dew-point adjustments of raw gas recycling condensate to the oil-gas-water separator and 2nd supersonic separator for CO2 removal avoiding CO2 freeze-out, give optimum net present value and minimum CO2 emissions. On one hand, these facts are consequences of less compressor investment as 2nd supersonic separator ejects pressurized CO2 condensate requiring 5% less compression power for enhanced oil recovery relatively to the power required by the low-pressure CO2-rich permeate from the membrane-permeation alternative. On the other hand, the best net value of supersonic separator alternative also reflects its highest revenues derived from recycling condensate from 1st supersonic separator entailing 18% higher oil production.

Carbon capture and adjustment of water and hydrocarbon dew-points via absorption with ionic liquid [Bmim][NTf2] in offshore processing of CO2-rich natural gas

Offshore oil production from huge reservoirs at deep waters with high gas-oil ratio and high carbon dioxide (CO2) content is a challenging puzzle because oil extraction imposes to process a huge flow rate of raw CO2-rich natural gas from which CO2 must be separated and sent to appropriate destination. Offshore gas processing comprises three steps: water dew-point adjustment (WDPA), hydrocarbon dew-point adjustment (HCDPA) and CO2 removal to avoid transport of inert and to boost oil production by injecting CO2 into the reservoir for enhanced oil recovery. In offshore rigs, gas is conventionally treated via TEG absorption for WDPA, Joule-Thomson expansion for HCDPA and membrane permeation for CO2 removal. This work discloses a new concept of CO2-rich natural gas processing using the ionic-liquid [Bmim][NTf2] for simultaneous WDPA, HCDPA and CO2 removal. All results were obtained via rigorous simulations, including the ionic-liquid implications in vapor-liquid equilibrium and heat-effects. The main novelty of the new process is its high-pressure selective stripping of CO2, lowering compression power for enhanced oil recovery utilization. Economic comparison of conventional gas processing with the ionic-liquid gas processing shows that the latter has 19.3% higher revenues, 23.6% less manufacturing costs and 18% less investment, entailing a 37% higher net present value.