bluuebunny/crossref_metadata_2025_split huggingface dataset:
Empirical Correlations for Quick and Accurate Hydrate Formation Prediction - Which One to Apply?
Authors: Khanna Anchit , Burla Ravishankar , Patwardhan Samarth 
Published: April 2019

Abstract
Natural gas hydrate formation is a costly and challenging problem for the oil and gas industry. Prediction of hydrates have been carried out through rigorous and laborious solving of mathematical equations called equations of state (EOS) which give accurate results but require appropriate setup and time. Few examples of such equations of state currently used by industry benchmarked software tools include Peng-Robinson (PR), Cubic-Plus-Association (CPA), Soave-Redlich-Kwong (SRK) etc. which more or less provide us with an accurate hydrate stability curve i.e. a pressure-temperature profile for a given composition, which allows us to keep the pressures and temperatures (operating conditions) out of the hydrate stability zone.
Hydrate stability curves are a function of the composition of the fluid (gas) being produced. Compositional changes in the percentage of C1 to C7+ components of gas, would not only affect the specific gravity, but would also change the hydrate stability curve of the gas significantly.
Previous studies have been aimed at finding a quick and precise prediction method for hydrate formation, so as to make swift arrangements to counter any chance of flow assurance issue. Different empirical correlations have been developed on the basis of the composition of the gas being produced that take into consideration the pressure and predict the temperature of hydrate formation. Multiple data points, i.e. fluid compositions from different areas/fields are considered and correlations have been developed to fit the hydrate stability zones of these data points which were found through a more accurate equation of state. As the initial data sets for each correlation are different, the possibility of any two correlations giving the correct and same prediction is very low.
This paper gives an insight into how different empirical correlations like Hammershmidt, Motiee, Makogon, Towler and Mokhtab etc., that have already been derived can be used with better accuracy for a set of different fluid compositions and specific gravities. A sensitivity analysis is done on the performance of each correlation against the accurate hydrate curves found out through the software tool, using different available equations of state. The data points picked here are random and were not included in any data sets adopted for derivation of the correlation.
Furthermore, the mimicked hydrate curve from this new method is cast against the software simulated hydrate curve for a flow assurance steady state simulation study with two deepwater gas wells with different gas compositions. The results of the study suggest that the use of the imitated hydrate curve through analytical approach works well in predicting the hydrate stability zone. It would also not require any software proficiency, would give quick results and would cost a fraction compared to the state of the art simulators.
Application of Concurrent Heat Transfer within the Wellbore for Passively Enhancing Oil Recovery by Reducing Deposition of Heavy Components of Crude
Authors: Sahu Ajay Kumar 
Published: April 2019

Abstract
Hydrocarbons are trapped at great depths with pressure and temperature higher than surface conditions which would vary depending on reservoir properties. When the well is set on production, these hydrocarbons travel through the wellbore over reducing geothermal and formation pressure gradients. Hence, at shallower depths the temperature drops below the cloud point and sometimes, below pour point of crude thus creating an ambient temperature for the formation of wax and deposition of paraffin on the inner side of production tubing.
It has been observed that when hot fluid passes through a pipe which is covered by a continuously circulating hot water bath, the temperature difference of the fluid at surface outlet and sub-surface reservoir is reduced to a minimal value. This paper therefore proposes a practical application of such heat transfer within a wellbore for passively solving major industrial issues of paraffin depositions. The idea lies in minimizing the heat losses, which can be effectively done by insulating the inner side of the casing so that the annulus and fluid flowing within the tubing is isolated from exterior losses. According to the First law of Thermodynamics the fluid flowing within the tubing will experience reduction in thermal gradient. These loses can be compensated by injecting hotter brine through a pipe at the bottom of the annulus, which is isolated, using production packer. Further, circulating hot fluid in the annulus would result in isothermal heating of the fluid flowing through the tube which would minimize the heat loss across tubing, causing an increase in temperature of fluid at the surface above pour point. Several researchers have put forth heat transfer equations across the tubing's, annulus, insulator, casing, cement and the formation which can be used to calculate the overall heat transfer coefficient and thus, the amount of heat losses. Quartz sensors placed at the bottom of a wellbore would detect bottom borehole temperature based on which the injection temperature of fluid can be manipulated. The entire process can be automated by applying an artificial intelligent system which would monitor, control and respond. This method would increase the capex but would decrease the operating cost thus leading to an increase in the life of the well.
Mitigation of Foaming by Using Pressure Pulse Technique
Authors: Jakkulwar Avi Diliprao , Das Barnali , Sengupta Partha , Santoshrao Pawar Anilkumar , Deuri Budhin 
Published: April 2019

Abstract
Foaming in absorber column for sour gas treatment using amine is a common problem which adversely affects column performance leading to reduction in sales and fuel-gas production and solvent loss. Mostly antifoam injection has been a common method to counter the foaming, large dosage and frequent dosing of antifoam many a times aggravates the problem. This study details an alternative technique based on pressure pulse mechanism to control foaming in one of ONGC's gas sweetening plants.
One of ONGC's amine based sour gas sweetening plants faced severe foaming problem frequently. The feed rate is 200 kscm/hr and absorber column operating pressure is 51 kg/cm2. The experiment utilizes the property of surface tension which fluctuates with change in pressure of the system leading to foam collapse. The experimental procedure involved varying the sour gas feed rate, thereby creating pressure pulse inside the absorber column. Differential pressure across the column which is an indicator of foaming tendency is then monitored and controlled within 1.0 kg/cm2 and recorded for establishing effectiveness of the method.
It is observed that by providing a number of cycles of pressure pulse in the absorber, the differential pressure stabilizes gradually which indicates collapse of foam. It shows that whenever there is increase in feed, expansion of bubble takes place which provides high interfacial liquid-vapour contact. On the other hand whenever there is decrease in feed rate, compression of bubble takes place which provides low interfacial liquid-vapour contact. Surface layer surrounding the bubbles in a foam acts as a membrane or skin that can stretch or relax in response to change in pressure and gives a mechanical shock which breaks the bubble. The increase of size ultimately leads to instability and break-up of the upper surface and releases the liquid holdup. Hence by using feed rate spikes, the pressure of the bubble is pulsed to higher levels and returned to substantially the original level. This cycle continues for a selected number of times so that this pressure pulse travels through the liquid and bubbles and affects its surface tension. This results into a transition phase which in very high energy level breaks the bubble and releases the gas and decreases the liquid hold up and controls the foaming phenomenon.
This paper will gives an insight into a novel methodology of mitigating foaming problem in a sour gas treating absorber just by varying the feed rates in a controlled manner. This technique eliminates the need for injecting antifoam agents which in turn will reduce the operating expenditure of the plant. Adverse impact on environment due to excessive use of antifoam agent is also minimized.
Pre-Laying of Flexible Lines Flownline and Riser and Floaters in Ultra Deepwater
Authors: Melilo Junior Angelo Celio , Oliveira da Costa Carlos Henrique , Armani Delalibera Carlos Alberto , Schwingel Dias Marco Antônio , Palmeira de Oliveira Thomaz Murrieta , Pereira Rafael Merenda 
Published: April 2019

Abstract
The Libra Extend Well Test (EWT) project is composed of 2 satellite wells interconnected to an FPSO with an external Turret anchor. One well is the producer, with 6-inch service lines and 8-inch production line in lazy wave risers configuration. The other well is the injector, with two 6-inch gas flow lines also in lazy wave compliant configuration. In the project planning several ac-tions were considered in order to guarantee the first oil date determined by the project, while the production unit (FPSO) was not available in the location and ready to pull-in campaign. One of these actions studied and later adopted was the pre-laying operation of the flexible lines with floaters in the lazy wave configuration of the production line of the production well. Later on, simi-lar studies were done considering the pre-laying of injection lines also. As this type of operation is not a track records at Petrobras for the ultra-deep water scenario, additional studies were nec-essary to ensure its feasibility and the safety execution. The objective of this article is to present the previous studies and the result achieved in the pre-laying operation of flexible line with float-ers in the lazy wave configuration of the Libra EWT service line.
Role of Culture, Processes and Systems for Safe Operations in Upstream Sector
Authors: Verma Prem Kumar 
Published: April 2019

Abstract
Upstream Oil & Gas Industry has witnessed improved HSE performance over time, by adopting latest technology and standards, engineering improvements, including hardware and adopting new processes and systems with maximum emphasis on safety with very good management systems. Compliance and audits have also improved a lot. However, improvement in culture, behavior and commitment at all levels are very important to deliver better business value in Personal and process safety.
Global energy risk engineering companies collate accident data over years and it is very clear that accidents continue to happen, which forces us to think methodology to improve personnel and process safety aspects continuously. It is observed that we are poor in assessing risk as we become used to risk, which could be due to over confidence, ignorance and safety culture issues. As per IOGP Incident Statistics, upstream process has improved over years, while we need to further improve in drilling operations.
It has been seen that Oil & Gas drilling industry is implementing personnel safety very rigorously with greater awareness, certified training programs, advanced technology, mock drills etc. However, Process safety in drilling industry needs greater emphasis. Some of the processes i.e. safety case, Risk and Control register with risk identification, assessment, response, financial impact, control, remediation and self-verification needs to be pursued rigorously. Processes and systems with organizational structure, quality of engineering decisions and understanding safety risk Vs commercial risk and suitable mitigation measures need to be pursued further. Decision hazards are very important to be analyzed including the process and lessons learnt. In addition to above, the basics of safety and the culture of caring for self, colleagues and the Assets are very important aspects.
This paper discusses the culture, processes and systems for safe operations in the upstream industry with special reference to drilling and completion operations.
Accurate Production Profiling in Deviated ESP Wells Affected with Recirculation with Advanced Production LoggingTool
Authors: Agrawal Gaurav , Kumar Ajit , Mishra Siddharth , Dutta Shaktim , Khambra Isha , Chaudhary Sunil , Sarma K. V. , Murthy M. S. 
Published: April 2019

Abstract
Objectives/Scope: XYZ is one of the marginal fields of Mumbai Offshore Basin located in western continental shelf of India. Wells in this field were put on ESP for increasing the production. Regular production profiling with traditional production logging was done in these wells to ascertain the water producing zones if any and do the subsequent well intervention if required.
Methods, Procedures, Process: In few deviated wells with low reservoir pressure, low flow rates and large casing size, massive recirculation was observed due to which spinner readings were highly affected. In such scenarios, quantitative interpretation with conventional production logging is highly difficult. Only qualitative interpretation based on temperature and holdup measurements can be made which might not completely fulfill the objective. In one of the deviated wells, massive recirculation was observed due to large casing size. Recirculation on ESP wells is generally not expected due to high energy pressure drawdown exerted on the well. Traditional production logging imposed difficulty in interpretation due to recirculation. Only qualitative interpretation was made from temperature and holdup measurements. Hence advanced production logging tool called Flow Scan Imager (FSI*) with 5 minispinners, 6 sets of electrical and optical probes, designed for highly deviated and horizontal wells to delineate flow affected due to well trajectory, was suggested for quantitative interpretation in such wells suffering with recirculation.
Results, Observations, Conclusions: In the next well, production profiling was to be done before ESP installation in similar completion as the last well. Therefore, huge recirculation phenomenon was expected in the well. FSI was proposed in this deviated well with recirculation for production profiling and also for finding out the complex flow regime inside the wellbore. FSI helped in proper visualization of the downhole flow regime with the help of multispinners and probes. Quantitative interpretation was made with the help of FSI data. Also, quantification was confirmed inside the tubing (lesser cross section area) where no recirculation is expected as the mini spinner does not collapse inside the wellbore. In traditional production logging, it is generally not possible due to the collapsing of full bore spinners inside tubing. Better understanding of the flow regime can be obtained with FSI than conventional production logging due to the presence of multiple sensors. Later interventions using FSI results have shown significant oil gains.
Novel/Additive Information: FSI was used in deviated ESP wells with recirculation for production profiling, accurate quantification, better understanding of flow regimes and to take improved well intervention decisions.
Digitization and Automation of Crude Transport Operations for Improved Safety and Security
Authors: Jami Satish , Shah Vishal 
Published: April 2019

Abstract
The rapid progress of technology such as big data and analytics, sensors, and control systems offers oil and gas companies the chance to automate high-cost, dangerous, or error-prone tasks. Most oil and gas operators are starting to capture these opportunities and doing well to accelerate their efforts. Companies that successfully employ automation can significantly improve their bottom line operations.
While automation offers many potential benefits in the upstream value chain of exploration, development, and production and transportation, some of the biggest opportunities are in crude transport operations, such as increased safety, security and decreased down time. Given the increase in oil and gas industry's substantial transport operations, optimizing these operations are essential. Automation creates several opportunities to that end: maximizing accuracy and efficiency in transport operations
This article is based on the application of digital technologies in the field of Crude Oil Transportation for improving Safety and Security while reducing the overall time taken for Crude Transportation Operations at Suvali Onshore Terminal. Digitization and automation of crude transportation operations in oil & gas industry leads to elimination of crude pilferage, elimination of manual errors, efficient crude loading operations, real time monitoring of crude transport operations, ease of measurements, reduction in disruption of crude tanker operations etc
Fractured Basement Characterization: An Integrated Approach for Play to Prospect Analysis and Resource Assessment of Basement Plays
Authors: Singh Manish Kumar , Dubey Siddharth , Chakraborty Subrata 
Published: April 2019

Abstract
This paper presents a multidomain integrated workflow that combines geophysics, borehole geology, fracture modeling, and petroleum systems analysis for characterization and resource assessment of basement plays. A 3D fracture model is developed by integrating image log interpretation and seismic data to assess the reservoir potential of fractured basement. The 3D fracture modeling is done using the discrete fracture network (DFN) approach with image log interpretation and other fracture drivers serving as the main input. The DFN is upscaled to generate fracture porosity and fracture permeability properties in a 3D grid. The upscaled fracture porosity is used to estimate the petroleum initially in place (PIIP) for the prospects. Multiple 2D petroleum system modeling is performed where large fault throws are identified from seismic interpretation. The petroleum system study helps in identification of areas with most prolific hydrocarbon generation and expulsion centers, which, coupled with the cross-fault juxtapositions, are the main locales of charging for basement reservoir. Further analysis of all the elements of basement play (i.e., source, reservoir, seal, trap, and migration) is done, and prospective areas within the basement play are delineated with high geological chance of success.
Planning India's First CO2-EOR Project as Carbon Capture Utilization & Storage: A Step Towards Sustainable Growth
Authors: Mishra Gaurav Kumar , Meena Rakesh Kumar , Mitra Sujit , Saha Kunal , Dhakate Vilas Pandurangji , Prakash Om , Singh Raman Kumar 
Published: April 2019

Abstract
India is the fastest growing major economy and third largest CO2 emitter in the world. Keeping cognizance of country's energy requirement and commitment to climate change, embarking upon technologies having minimal carbon footprint is the need of the hour. Carbon capture, utilization and storage (CCUS) is one such technology which offers dual benefits of carbon sequestration & enhancing oil production from mature oils fields. This paper outlines ONGC's efforts in bringing nation's first CO2-EOR project.
In view of non-availability of natural CO2 sources in India, usage of anthropogenic CO2 captured from thermal power plants was conceptualised. Based upon CO2 source-sink matching exercise and favourable reservoir & fluid parameters, two oil fields were screened. Technical feasibility of CO2-EOR was first ascertained in laboratory by determination of minimum miscibility pressure (MMP) of CO2 through slim tube experiments. Encouraged by laboratory results, full field compositional simulation studies along with fluid characterization inputs from PVT simulator were carried out.
The MMP were found to be in range 190-250 Ksc, which is below the initial reservoir pressures of the targeted reservoirs. The proposed scheme entails drilling of around 70-80 wells inclusive of both producers & injectors and has the potential to yield an incremental recovery between 10-14 %. A sensitivity analysis based upon purity of CO2 and its adverse effect on MMP was carried out in terms of reduced oil recoveries. Since, this shall be a CCUS project, CO2 from the produced stream has to be separated, compressed and reinjected in a closed loop system. Around 5-8 MMT of CO2 will be sequestrated through Structural, Solubility and Residual trapping mechanisms as modelled in compositional simulator. IFT reduction & decrease in Sor (Residual oil saturation) as result of swelling, miscibility of CO2 with native oil were also modelled in simulator. Being first of its kind project in India, there are many inherent challenges to the CCUS project. At the source end, capturing CO2 from flue gas stream and its compression & transportation is a cost and energy intensive process. At the Sink end, CO2 being acidic and corrosive gas will need retrofit modifications in terms of special corrosion resistant metallurgy for existing processing facilities.
The learning curve from this endeavour shall create knowledge base to further expand deployment of CCUS in India, bringing a large portfolio of reservoirs under the ambit of CO2-EOR. Success of CCUS in India will not only increase domestic oil production but also cater to address the National INDC of reducing emission intensity of GDP by 33-35 percent by 2030 as per Paris agreement.