Gupta, M K (Oil and Natural Gas Corporation Ltd) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd) | Singh, V K (Oil and Natural Gas Corporation Ltd) | Pawar, A S (Oil and Natural Gas Corporation Ltd) | Deuri, BUDHIN (Oil and Natural Gas Corporation Ltd)
In an offshore field, mitigation of H2S from natural gas itself is a big challenge. A situation where high H2S present in well fluid increases the challenges several fold to sweet both processed oil and gas. In a wellhead platform/remote location where manual intervention requirement is minimal, conventional process has several limitation such as space availability, load on structure, frequent monitoring etc., hence may not be suitable for mitigation of H2S from processed gas and oil.
In this work, an approach is adopted for sweetening of sour gas and sour crude in an optimum way, keeping offshore constraints in mind and without usage of rotating equipment's. An integrated simulation model is developed in Aspen HYSYS process simulator wherein well fluid from well manifold is processed in three phase oil and gas separator. The gas liberated from the separator is first sweetened in adsorption columns considering three bed systems unlike general usage of two. The oil is sweetened in an envisaged stripper column utilizing sweet gas from adsorption column as stripping gas. In this work, a three bed adsorption column is envisaged wherein 1st two column in used for sweetening of gas liberated from separator which consists of around 7500ppm H2S. Sour oil from the separator which contains around 2000 ppm of dissolved H2S is processed in a stripper column for mitigation of H2S dissolved in the oil. Sweet gas liberated from 1st two column of adsorber bed is used as stripping gas for oil sweetening. H2S liberated from stripper column is routed to the 3rd column for sweetening. After this gas from all the adsorber column is combined and routed to process platform along with the sweet oil. Analysis reveals that, this scheme can sweeten altogether both oil and gas to the desired H2S level without the need of any rotating equipment's and must be a suitable for remote location.
A holistic approach was taken for sweetening of oil and gas without the need of any rotating equipment's, & any chemicals, unlike the conventional method and hence can be suitably adopted for an offshore environment or at remote location where requirement of manual intervention is bare minimum.
Gupta, M K (Oil and Natural Gas Corporation Ltd.) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd.) | Singh, V K (Oil and Natural Gas Corporation Ltd.) | Bansal, R (Oil and Natural Gas Corporation Ltd.) | Pawar, A S (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.)
This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications.
A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations.
An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.
Gupta, M K (Oil and Natural Gas Corporation Ltd.) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd.) | Singh, V K (Oil and Natural Gas Corporation Ltd.) | Pawar, A S (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.)
In one of the offshore complex of ONGC, Carryover of liquid have been observed leading to tripping of gas compressors resulting a loss of significant amount of production. It was established that separation capacity of existing separators even at present operating conditions were not sufficient to process present production. Further an increase of 60% of present gas production is envisaged as per long term production profile. Hence, handling the present and envisaged increased production in the existing separators was explored.
To handle the envisaged enhanced production rate and to avoid carryover issue in existing separators, options such as feed nozzles enhancement and installation of inlet device was explored. Changing feed nozzles is a tedious job, require hot job and longer shut down period and requires complete integrity test of separators as recommended by ASME SEC-VIII, pressure vessel guidelines followed by R-stamping. Therefore modifications in separator internal was suggested which will enhance the separation capacity and can accommodate in the present and envisaged increase of future production.
The analysis revealed that even though the diameter and length of the separators are adequate to handle the load, it was established that the inlet nozzle of the separators are not adequate. Hence, considering many factors such as minimum pressure drop, ensuring good gas distribution, suppression of re-entrainment, momentum reduction and erosion velocity ratio of less than one, modifications in separator internal was suggested which will enhance the separation capacity and can accommodate the present and future envisaged increase of production of more than 60%. It was established in the study that this options of installation of inlet device can be done with minimum modifications and require minimum shutdown period. This option has been recommended and is under field implementation. Hence this work will provide a significant help to oil and gas personal to accommodate higher than design feed quantities in existing separators with minimum modifications and minimum shutdown period.
One of the largest onshore process complex receives and processes sour gas, condensate and crude from the offshore fields. Due to ageing of existing fields and production from new fields with different reservoir fluid characteristic, the composition of gas varies considerably with respect to the composition at inception, especially with reference to C3+ components. Opportunities were explored for enhancement of recovery of heavier components for value addition from the available gas in the existing scenario.
Presently, irrespective of their richness, with reference to C3+ components, all the gas streams such as slug catchers gas (molecular weight around 20.65 to 21.02), off gases from stabilization units and condensate fractionation units (molecular weight around 25.11 to 27.12) are combined and are routed for gas processing with the resultant combined gas molecular weight of around 21.01.
To evaluate the effect of processing of only rich gas streams in an exclusive gas sweetening unit and then further processing at a LPG unit was conceptualized by means of an integrated simulation model developed in Aspen Hysys process simulator.
Simulation model was calibrated and matched with the existing field operating parameters. All the rich gas streams such as one of the rich trunk line gas (molecular weight around 21.02), off gases from stabilization (molecular weight around 25.11) and fractionation units (molecular weight around 27.12) were segregated and processed in an exclusive gas processing train. Study established that the envisaged resultant combined rich gas molecular weight will be around 22.01. An analysis of preferentially processing of rich gas in one of the LPG unit with reference to production of LPG & Naphtha was carried out. Study examined the adequacy check of existing equipments such as pressure vessel, pumps, columns, exchangers, pipelines and their control valves. Study reviewed the modification requirements and also indicated the optimum parameters such as temperature, pressure to be followed in various processing units for effective recovery of heavier components from the gas.
The study established that preferential processing of rich gas in one exclusive train of gas sweetening unit and then in turbo expander-propane based LPG extraction unit resulted in enhancement of around 17% increase in LPG production and around 2.6% increase in Naphtha production from the existing production level of the complex.
Presently no provision exists to preferentially process the rich gas stream. Study elaborates the ways and means to be adopted for preferential processing of rich gas in the complicated gas processing complex considering flow, pressure, and temperature parameters including safety & flexibility of the plant operations by simple modifications.
This case study highlights the hidden opportunities in an existing processing complex to enhance the product yield and to gain additional revenue generation.