bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancement of Dry Gas Seal Reliability
Authors: Sahadevan Roy , Al Menhali Basma 
Published: November 2018

Abstract

Objective
Shaft sealing prevent uncontrolled escape of process gas from the gas compressor casing. During shaft sealing failure, apart from loss of production, consequences due to loss of containment of hazardous and toxic process fluid may extend to multiple fatalities and major asset damage. Due to this high risk, the operation team is highly focused in improving reliability of compressor seals.
Over the years, traditional oil film seals are replaced by dry running gas seals. Most of the process gas centrifugal compressors manufactured today are equipped with dry gas seals. Dry gas seals are available in a variety of configuration; the most common one for process gas application is tandem seals.
This report describes a centrifugal compressor dry gas seal (tandem seal) failure investigation in an oil and gas field and the recommendations to enhance gas seal reliability.
Dry gas seals in a medium pressure, hydrocarbon gas compressors had experienced frequent failures, to be precise, five dry gas seals failed in a span of seven months. These frequent failures become a serious challenge to sustain gas production.

Analysis
Data for analysis was gathered during site visit, in addition, discussion with operations & maintenance team was held to understand equipment performance and maintenance status. Real time operational data was obtained from data server for selected parameters.
Defect elimination is the method used for analysis, this include identifying all possible causes of failure. The trends on key operating parameters that have the potential impact on seal failure and the variation of these parameters during the event are analyzed. The report describes the details of analysis performed.

Results and conclusions
An evidence based approach is used either to qualify or eliminate the cause of failure. The report indicates the most likely cause of seal failure based on the method of analysis.
This report describes the modifications in the system and operating requirements to prevent future dry gas seal failures. Modification includes additional instrumentation for monitoring to increase safety of existing equipment and systems.
Site utility conditions, compressor operating conditions, control and monitoring of key parameters can significantly influence dry gas seal reliability and requires special care in the design of seal auxiliary systems. By providing proper training to operators and maintenance team the seal reliability can be enhanced.
Dry gas seals in critical rotating equipment are very common in the oil and gas industry. Seals can fail for a variety of reasons, hence improving reliability of gas seals is important for the operations to achieve hydrocarbon production targets.
Screening of New HPAM Base Polymers for Applications in High Temperature and High Salinity Carbonate Reservoirs
Authors: Alfazazi Umar , AlAmeri Waleed , Hashmet Muhammad Rehan 
Published: November 2018

Abstract
Application of polymer flooding technique under extreme reservoir conditions (~120°C and 167000 ppm) is still of great concern. In high temperature and high salinity (HTHS) reservoirs, the commonly used polymers for improved oil recovery purposes are ineffective due to chemical degradation and poor injectivity. Therefore, the aim of this paper is to screen partially hydrolyzed polyacrylamide (HPAM) base polymers in order to find suitable polymer for a targeted HTHS carbonate reservoirs.
Polymer screening study was carried out on three new NVP-HPAM base polymers to identify a potential candidate which can withstand harsh reservoir conditions. Initially, a comprehensive rheological study was conducted at various polymer concentrations (1000-4000 ppm) and brine salinities to investigate the effectiveness of the polymers. Then, thermal stability test was conducted at anaerobic condition and 120°C for three months. Finally, injectivity test was conducted with the best polymer and in the absence of oil at 120°C and formation salinity (167000 ppm). The experiment was done by sequential injection of 3 polymer concentrations (3000, 1500, and 750 ppm). Parameters such as resistance factor, residual resistance factor, insitu rheology, and apparent shear rates were investigated during the experiment.
Results from the rheometric studies showed that all three polymers have acceptable initial viscosifying properties at ambient temperature and shear thinning behaviors within shear rate range of 1-100 s-1. The results also indicated that polymer viscosities dropped with increase in temperature and salinity. However, they still showed good resistance up to 167000 ppm and 120°C. The thermal stability test for the potential polymer showed better stability and retained more than 90% of its initial viscosity after the ageing period. Whilst injecting at 3000 ppm, the resistance factor (RF) was between 20-10 (at different flowrates). During 1500 ppm and 750 ppm, the RF were in the range of 14-6.5 and 5-2.7 respectively. At low flowrates (0.05-1.0 cc/min) of polymer injection, shear thinning behavior was observed. Whereas, shear thickening behavior at high flowrates was observed at all concentrations. Finally, the residual resistance factor (RRF) recorded for the injectivity experiment was found to be 6.17.
The potential polymer showed promising results for its application in heterogeneous carbonate reservoir with higher temperature and salinity of 120°C and 167,000 ppm respectively. The study also leads to better understanding of polymer flow behavior in high temperature high salinity carbonate reservoirs.
Drilling Automated Realtime Monitoring Using Digital Twin
Authors: Gholami Mayani Maryam , Rommetveit Rolv , Oedegaard Sven Inge , Svendsen Morten 
Published: November 2018

Abstract
Having a Digital Twin of the drilling well, pairing digital and physical data combined with predictive analytics and diagnostic messages, improves accuracy in planning and decision making of the drilling operation. It helps the industry to increase safety, improve efficiency and gain the best economic-value-based decision as well as reduce operational cost. Today advanced monitoring is normally done using real-time measurements, compare pre-simulation results with measurements, perform manual diagnostics and run new simulations when abnormalities are seen. All done manually by people.
Drilling can move beyond advanced monitoring using Digital Twin's by implementing automatic ‘forward-looking’ and multiple ‘what-if’ simulation to give operations the optimal plan with focus on safety, risk reduction and improved performance.
The Digital Twin examples in the current paper can do more advanced and complex automatic forecasting simulations, diagnostics, ‘forward-looking’ and ‘what-if’ simulation as well as predictive analytics in the wellbore in the 2D and 3D simulation view.
By using the advanced models (Digital Twin), all relevant challenges and risks were identified during the drilling operations of one well under high pressure high temperature (HPHT) conditions. The stand pipe pressure (SPP), equivalent circulating density (ECD) and temperature behavior were studied during the drilling and circulation of this well. The Digital Twin was also used to evaluate possible losses during 9 7/8″ casing running and cementing with special focus on when casing was passing through the formations. In another well the Digital Twin triggered an early notification regarding high cuttings concentration during drilling 8 ½″ section. The flow rate was adjusted and helped to prevent sidetrack and pack-off due to losses.
Morover during drilling 17 ½″ section in another case, large losses were prevented by comparing the modeled active pit calculation and measured tank volume. The Digital Twin enables advanced automatic forecasting simulation, self-diagnostics, automatic ‘forward-looking’, multiple ‘what-if’ simulation and predictive analytics to improve safety, reduce risk, increase drilling performance and reduce costs.
Increasing Stimulated Reservoir Volume SRV in Unconventional Reservoirs: Microstructural and Rock Mechanical Study
Authors: Mustafa Ayyaz , Tariq Zeeshan , Abdulraheem Abdulazeez , Mahmoud Mohamed , Al Nakhli Ayman , BaTaweel Mohammed 
Published: November 2018

Abstract
The huge resources of unconventional hydrocarbon reserves across the world coupled with the growing oil value makes their contribution to be significantly important to the world economy. Oil producing companies can invest in unconventional hydrocarbon to cover local demand and save crude oil for exporting. Conversely, one of the foremost challenge that producers face in unconventional reservoirs is the need for large stimulated reservoir volume (SRV) to ensure economical production.
This study describes a new stimulation technique to increase the stimulated reservoir volume using the chemical reactions along with hydraulic fracturing fluid. Reactive chemicals are used to generate the localized pressure and heat in tight formations to create additional micro fracturing, thus increase the fracture complexity. Created induced micro-fractures considerably increased the porosity, permeability, and ultimately the SRV. The synthetic sweetspots are created nearby a wellbore and fractured area by the help of new stimulation treatment mechanism. Results showed significant conductivity increase with new treatment technique.
Rock samples were studied for mineralogical and microstructural characterizations using advanced spectroscopy and microscopy analytical techniques. Moreover, on each rock specimen ultrasonic compressional (P-wave) and shear (S-wave) velocities were recorded and dynamic Poisson's ratio and Young's modulus were determined. The obtained topographical images revealed the presence of micro-cracks and nanoscale pores in all studied core samples.
The novelty of this study is to develop a novel fracturing technique to increase stimulated reservoir volume (SRV). The parameters studied in this research can be served as critical inputs for many field applications such as wellbore stability, casing design and perforation, sand production control, and fracturing.
Targeting the Permo-Triassic Tight Gas in the Khuff: Lessons Learned in the Journey towards Development, Offshore Abu Dhabi, UAE
Authors: Steiner Stefan , Dasgupta Suvodip , Basioni Mahmoud , Al Aryani Fatima , Noufal Abdelwahab , Mills Carey , Mandl Johannes , Menon Pradeep , Raina Ishan , Mosse Laurent , Shasmal Sudipan , Hollaender Florian , Ali Humair , Al Afeefi Baraka , Sookram Neil 
Published: November 2018

Abstract
Exploration drilling for gas potential in Khuff Formation started more than 40 years ago and wells across multiple assets in offshore Abu Dhabi showed the presence of sizeable reserves. With increasing recent importance on gas production, there is a plan for moving towards development for those Permian tight gas structures to address the nation's gas needs. This paper will try to address the lessons learned from the recent appraisal wells in Khuff, the uncertainties and the success criteria.
There have been multiple wells drilled through the Khuff Formation in Offshore UAE in the last two years and have yielded a wealth of information from downhole well logs, mud logs, well test results and core data. The downhole logs acquired in these wells ranged from basic triple-combo and mud logs to image and dipole sonic logs, along with formation testing and sampling measurements, followed by well tests across the zones of interest. Interpretation of all these data have revealed some interesting lessons learned.
The shallow marine sequence of the Khuff Formation is generally characterized by poor porosity and low matrix permeability; however, the diagenetic overprint has resulted in a significant heterogeneity development, which controls the present-day porosity and permeability development at the wells. The well test results show variations in terms of 2 or 3 orders of magnitude at the same interval, which highlights potentially problematic development strategies. We have observed significant differences in terms of lithology, porosity and other reservoir quality indicators between wells, located a kilometre apart. Optimization of logging suite to minimize petrophysical evaluation uncertainty will be discussed. Characterising this heterogeneity is key for future economic success of this play. Possible role of fractures influencing flow from the Khuff have been discussed in older publications, however no conclusions were arrived at, with certainty. Presence of fractures and faults beyond the immediate vicinity of the well might be something to look at, in terms of understanding the potential productivity of those intervals. A big step for developing Khuff Formation might be in terms of deciding the optimal stimulation strategy and this is something, which remains to be studied extensively in UAE.
Closing the loop of interpretation of the acquired logs with the final well-test results and production logs gives us the advantage of hindsight and helps us in separating out the key productivity indicators as well as bring out the uncertainties in formation evaluation, which affect these tight gas reservoirs.
A Novel Dynamic Assessment of Multi-Stage Hydraulic Fracture Propagation in Presence of Natural Fractures in Shale Gas Reservoirs
Authors: Suboyin Abhijith , Rahman Md Motiur , Haroun Mohamed , Shaik Abdul Ravoof 
Published: November 2018

Abstract
Augmented by the recent activities in unconventional reservoirs, it can be easily said that hydraulic fracturing has become a pivotal component for the successful development of unconventional reservoirs. This novel study deals with the investigation of fracture propagation behavior in shale gas reservoirs under varying controllable and non-controllable parameters. In addition to the analysis of propagation behavior, their interaction in the presence of natural fractures are reviewed and quantified.
It is highly challenging to quantify and address the distinct contributions of an element due to the level of heterogeneity that is present in reservoirs. In-situ stress has been reported to be such a dominant contributor to the fracture propagation behavior as they are imperative to assess the extent and the direction of fractures. An enhanced dynamic simulation was conducted to investigate fracture propagation behavior in shale gas reservoirs under varying parameters which were categorized as controllable and non-controllable with respect to the fracture design, treatment and drilling process. After an extensive assessment, a set of natural fractures were introduced to the system and the system behavior was further analysed.
The constructed model is verified with traditional and published models to validate the generated results. It is illustrated that even modest variations of the associated principal stresses between the target zones and the bounding zones can severely limit hydraulic fractures. Further simulation runs under varying fluid conditions and its associated properties revealed similar observations. With the introduction of natural fractures, it is demonstrated that the distribution of the natural fracture network plays a critical role in the cumulative gas production along with its description. Additional investigation illustrates and verifies that fracture width assists in better performance as compared to fracture length for the defined conditions. Fracture placement along with its orientation and proppant properties are also considered to further examine the associated response on productivity.
This novel investigative approach will create a paradigm for future studies that will assist in a simplified prediction of fracture propagation behavior, its associated drilling parameters and anticipated response. In addition, an extensive investigation for the quantification of changes with respect to the variation in prime contributors is presented, which assists in the validation of modern best practices approach.
Reservoir Ranking Map Sketching for Selection of Infill and Replacement Drilling Locations Using Machine Learning Technique
Authors: Li Yuanjun , Samuel Robello 
Published: November 2018

Abstract
Infill and replacement drilling are effective ways to improve oil recovery as increasingly more wells are drilled in close proximity for fracturing. Presently, the approaches being employed are logging surveys, the moving window method, the rapid inversion method, and the customized type curve method. However, these methods are not suitable for reservoirs with high levels of heterogeneity in terms of geology, and require more expert knowledge and field survey, which can be time consuming and costly. Therefore, the present method developed is an economic and fast approach to determine infill and replacement drilling location from reservoir ranking maps generated in combination with machine learning methods.
During this project, production data and reservoir parameters were gathered from an old oil field with more than 2,500 wells where most of the field was under water injection. Bubble maps were created for each reservoir parameter for a better visual representation of reservoir conditions. Then, after data cleansing and normalization procedures, the standout attributes were identified from all given reservoir parameters and production history and a reservoir ranking rule was set. Next, five types of classification approaches were used for prediction. This paper additionally presents a regression method, artificial neural network (ANN), to compare with the prediction results from classification. For each machine learning technique, a reserve ranking map was generated for this test field to predict future infill drilling and replacement drilling opportunities. Thus, with only geographic coordinates, the reserve ranking level was obtained.
From cross-fold validation results, a quadratic support vector machine provides the highest prediction accuracy. From a practical standpoint, a decision tree offers a more realistic result. In addition to the ANN method outputs, the ranking result provides a smooth method between certain levels. This new approach of using artificial intelligence was used to provide the ranking level and ranking number to identify the best options for drilling the wells, which is different from the present traditional methods. This advanced reservoir ranking map allows operators to identify the best location for infill or replacement drilling. It can additionally help operators benefit from their previously gathered knowledge in a cost-effective way.
A Novel Power Generation System Utilizing Un-treated Sour Gas Fuel
Authors: Xijia Lu , Miles Palmer , Brock Forrest , Mike McGroddy 
Published: November 2018

Abstract
A significant portion of natural gas reserves around the world contain large quantities of sulfur species and carbon dioxide, which are often referred to as sour gas reservoirs. The IEA reports that more than 40% of the world's gas reserves are sour, with the number increasing to 60% for Middle Eastern gas reserves. Sulfur species, such as hydrogen sulfide (H2S), are highly corrosive when mixed with water and toxic to biological organisms. Compounds such as SO2 and SO3, which are derived from direct sour gas combustion, are also highly corrosive when mixed with water at the condensation temperature of sulfuric acid. Therefore, removal of H2S to trace levels from natural gas is typically considered as the first step of the utilization of sour gas for power generation. This paper presents a novel method which enables sour natural gas to be directly burned for power generation without pretreatment. Oxidized sulfur compounds are captured by limestone in the combustion process to eliminate downstream sulfur corrosion. The desulfurized flue gas then goes through a solids removal process before entering a gas turbine or a turbine expander for power generation. A steam cycle is used for waste heat recuperation from both the turbine exhaust stream and the solids stream to improve the cycle performance. Both air-combustion and oxy-combustion configurations were investigated and modeled using Aspen Plus. The design conditions of each cycle are within the operating envelope of commercially available equipment, including compressors, turbines and heat exchangers, enabling near-term deployment of the presented system. Aspen modeling results show the range of efficiency percentages for different cycles is from the low 40's to the low 50's on a Lower Heating Value (LHV) basis. Without pretreatment, the heating value of sulfur in the sour gas and the heat released from the limestone scrubbing process can be fully utilized for power generation, thus improving the cycle performance. Economic analyses estimate that the baseline air-combustion sour gas system with a conservative estimated Capex ($2142/kW) is 41% cheaper than NGCC in 2011, and is about 28% cheaper than advanced NGCC in 2022 on a simplified Levelized Cost of Electricity (LCOE) basis. The LCOE of the oxy-combustion sour gas system is estimated to be 53% lower than advanced NGCC in 2022 when the revenue from CO2 and Argon sales is taken into account. Therefore, the novel untreated sour gas combustion system presented in this paper enables the petroleum and power industries to use sour gas for power generation more efficiently and cost effectively, even with full carbon capture.
An Innovative Technique to Sustain Well Performance
Authors: Channa Zohaib , Al Qubaisi Salama , Al-Neaimi Ahmed Khaleefa , Al Syari Ahmed Mahfoudh , Al-Shehhi Omar Yousef , Nofal Salman , Khan Mohamed Navaid , Ahmed Fazeel , Khemisa Hocine , Al Feky Mohamed , Abdel-Aziz Mahmoud , Gutieirrez Freddy , Obeid Ahmed Fayyad 
Published: November 2018

Abstract
In the case study field, most of the wells are being completed with dual strings where there is no accessibility in the upper zone (short string). This leads to no well intervention in the future if there is any gas or water breakthrough or in some cases the formation collapse. However, formation collapse was recently observed in the certain dense (impermeable) layers which are liable to hole collapse when in contact with HCl acid during stimulation operation hence resulting in hole plugging. This leads to losing the production / injection from the upper zone and requires rig workover to clean out and recomplete the well. This phenonmenon was further confirmed by several experiments performed on different core samples in the Lab. A quick and cost effective solution was looked into and found that 4-1/2" liner, called "drop-off", can be run and set in the upper drain of the well to avoid any future breakthroughs or hole collapse. 4-1/2" drop-off liner was successfully run in multiple wells and proved to be very efficient. This cost effective innovative technique resulted in restoring the wellbore stability and help in sustaining the production from the upper drain.
Well Design Evolution, Validation and Optimization in ADNOC Onshore GAS Field
Authors: Yugay Andrey , Gadelhak Abdelrahman Mohamed , Pimenta Gervasio , Al Reyami Mariam Mansoor 
Published: November 2018

Abstract
In early 80's in ADNOC Onshore standard well completion design for gas producers in Reservoir Y of Bab field was a combination of L-80 carbon steel with a downhole continuous corrosion inhibitor injection above the Chemical Injection Valve (CIV) and Corrosion Resistant Alloy (CRA) Incoloy 825 / SM25Cr-75 below the CIV and packer.
In 1994 (after 10 years of operation), due to the fact that no integrity issues were observed, it was decided to maintain the same design strategy was followed in all new gas producer wells in this reservoir. Identical design strategy was followed for Reservoir X (Project-I) gas wells which presented less severe fluid conditions. Table 1 summarizes reservoir conditions for both reservoir X and Y.