bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimized Coiled Tubing Based Milling of Multiple Composite thru Tubing Bridge Plugs in High Condensate Hydraulically Fractured Deep Gas Wells - A Case Study
Authors: Vijayvargia Utkarsh , Tiwari Shobhit , Anand Saurabh , Sidharth Punj , Sharma Anurag , Janardan Yadav Kumar Manish , Goyal Rajat 
Published: November 2016

Abstract
Raageshwari Deep Gas field is a relatively deep (2800-3500 meters) unconventional volcanic reservoir with pressure and temperature of ~ 5200 psi and ~ 140 degC respectively. Wells were completed as 3-1/2" Monobore producers and plug & perf method was used for fracturing stimulation. 3-1/2" 10000psi rated millable bridge plug was installed immediately after the fracturing stimulation which were then milled by coiled tubing based milling tools to clean up & test all the zones commingled.
During milling of bridge plugs, substantial amount of gas along with significant condensate was produced from the zones, which resulted in vast variance in Coiled tubing circulating pressures and well head pressures. As a consequence, WOB was increased, in an effort to speed up the milling process. Unfortunately this resulted in frequent motor stalling and inefficient milling. Also, managing large amount of produced gas and condensate, along with milled cuttings, sand, gel and water, was an issue with regards to conventional surface equipment’s and frenzied flaring of condensate in vicinity of other gas producing wells.
This paper describes how the bridge plug milling process was optimized over the course of the campaign of hydraulically fractured gas wells. This optimization included all aspects of the milling operation such as, WOB, penetration rate, milling fluid system which facilitated the increase in frac fluid recovery, as well as the differential pressure across the motor. This optimization reduced the bridge plug milling time to between 30 and 45 minutes. It also summarizes the challenges which had to be overcome during the successful implementation of this technique and the lessons learnt in due course of time. This paper also describes the use of a sand catcher along with the conventional surface well testing unit and an inventive surface rig up which not only assisted in perfectly managing the milling cutting, sand, gel and water at surface, while completely eliminating the requirement of flaring the condensate.
The technique helped save about 5% of the total well cost well by reducing the number of days required for milling operations and the associated daily rental of surface well test and Coiled tubing spreads. This technique also ensured minimum flaring of hydrocarbons and faster hookup of wells to production facilities and therefore is strongly recommended in high condensate gas wells located in environmentally sensitive locations with HSE and economic concerns.
A Technical Evaluation of Hybrid Membrane-Absorption Processes for Acid Gas Removal
Authors: Sclierf Michael , Rufford Thomas E. 
Published: November 2016

Abstract
This paper assesses two possible acid gas removal processes for CO2 removal onboard a floating LNG facility: (1) the well-established amine absorption process, and (2) a membrane/amine absorption hybrid process. The assessment considers process and economic aspects as well as sizing due to the on-board application.
Process simulation models of each of the systems were developed in the Aspen Hysys (V8.6) software package. Two different gas fields are assumed with Feed1 containing 10%/0% CO2/H2S and with Feed2 50%/1% CO2/H2S. The feed rate in each scenario was 590,000 Nm3/h and the sweet gas specification was 50 ppm CO2 and 4 ppm H2S. The amine absorption process modelled as the base case was a 50% MDEA solution. The hybrid membrane/amine process featured a polymeric membrane unit implemented as a sub-flowsheet and then the amine unit.
Our results suggest that for a very sour gas feed there may be advantages with a hybrid membrane/amine process that allows the plant weight to be reduced by 80%, volume by 50%, investment costs by 70% and annual operation costs by 40%. The most important disadvantage concerning the hybrid process is the high methane slip which can be reduced by further development of membrane properties and process design. The participation of the membrane unit increases generally with the percentage of acid gas in the feed. If the boundary conditions are comparable to those used in this paper, it can be stated that the CO2 concentration should be at least 10% for a proficient application of a hybrid process.
This study presents models to evaluate novel acid gas removal processes and describes suitable process metrics that could be considered for floating LNG production facilities.
Real-Time Enabled Workflows Help Reduce Drilling Events, Minimize Drilling Times and Anticipate Production in Extra Heavy Oil Asset
Authors: Carrillo Luis A. , Gomez Juan C. , Castaneda Jorge A. , Rueda Rodolfo M. , Urribarri Orlando J. , Neri Victor , Corrales Juan F. 
Published: November 2016

Abstract
At the beginning of 2015 in response to the well construction difficulties faced by drilling companies such as lost circulation, slow Rate of Penetration (ROP) and increasing flat times observed while drilling in an extra heavy oil asset in the Gulf of Mexico, the operator implemented a real-time drilling monitoring center called Centro Inteligente de Pozos (CIP by its Spanish acronym).
The whole purpose of the team and technologies deployed at the CIP is to Anticipate and prevent drilling events; effectively and systematically reduce drilling Nonproductive times (NPT); implement best practices aimed to optimize drilling performance and operate closer to the wells’ technical limits; and accelerate initial oil production by finishing wells before expected.
The CIP solution is comprised of a very well balanced combination of technologies, resources and processes as follow:
Data acquisition, transmission and visualization: Vendor neutral technologies and services are deployed in both ends the rig and the office to enable data collection, integration, aggregation and transmission.
Risk analysis: For each well and prior to start drilling, the CIP team prepares a detailed drilling risk analysis, which includes risk description, prevention and mitigation practices.
Drilling optimization: CIP’s engineers use specialized drilling monitoring software to analyze available data, managed identified risks, optimize performance, and make operating recommendations to exceed performance while drilling within the wells’ technical limits.
At the CIP, the well-coordinated efforts between the operator and the service company in conjunction with the application of efficient processes and innovative technologies, have been cornerstone to reach drilling optimization while minimizing the negative impact of drilling events; making the CIP initiate a success for the operator and service companies.
As a result of implementing the CIP, wells in the Extra Heavy Oil Asset have been drilled in record times. For example, a well that was originally planned to be drilled in 116.7 days was drilled in 89.9 days. This represents total savings of 26.8 rig days (~23% time saved), with a corresponding oil production estimated at 6,000.00 bpd.
Our industry constantly strives to drill faster and safer wells while drilling in more challenging environments. In the author’s opinion one way to achieve this is by adapting classic surveillance procedures with modern workflows based on real-time data and considering relevant analysis such as risk estimation, real-time geomechanics and flat times optimization. The work described in the following pages represents the first successful application of advance real-time drilling monitoring techniques in the Extra Heavy Oil Asset matter of this paper.
Enhanced Deepwater Conductor Jetting Design for East Malaysia
Authors: Prasertamporn Praisont 
Published: November 2016

Abstract
Conductor jetting has been the preferred installation method for deepwater drilling. This type of installation depends on the skin friction between the conductor and the formation, making axial load capacity the critical success factor. Failure of axial load resistance causes well subsidence, incurring high cost in a deepwater environment. In principle, a longer conductor length gives higher axial capacity.
The PSC Company has drilled deepwater wells in East Malaysia and plans to drill more wells in the future. The conductor was designed using the same parameters as the nearby fields and the historical data. In addition, third-party companies normally perform conductor analyses based on the Gulf of Mexico soil set-up rate, which is not similar to East Malaysia. These practices have inadequate theoretical support and could lead to failure.
The paper objective is to analyse the conductor length requirement for East Malaysia with The PSC Company's planned conductor. The analysis includes the conductor length requirements for different well parameters.
The soil profile was derived from the nearby field soil-boring data and previous well parameters to obtain the soil set-up curve. The soil profile was matched with various parameters to analyse the required conductor length. The result describes the significant effect of conductor and jetting bottom hole assembly weight. Higher weight gives more weight on bit, providing high immediate capacity and requiring a shorter conductor. In addition, setting long 20" casing imposes a higher load that requires a longer conductor. However, PAD mud weight and duration before land weight on the conductor do not provide a significant effect. Moreover, other conductor specifications that may be run in the future were analysed, showing the same tendency, where a heavier conductor requires a longer conductor.
This analytical method can be recalibrated for other conductor configurations in the future.
The information contained herein is provided with the understanding that the COMPANY makes no warranties, either expressed or implied, concerning the accuracy, completeness, reliability, or suitability of the information.
Hexapod Pilot Tests Determine the Influence of 3D Motions on the Performance of an Amine-Based Acid Gas Removal Unit Installed on a Floating Support
Authors: Gauthier Perdu , Clément Salais , Vincent Carlier , Claire Prosernat S. A Weiss , Thomas Maubert , Pascal Alix , Manel Fourati , Philippe Béard , Graeme White 
Published: November 2016

Abstract
The objective of this paper is to present new improvements in the knowledge of the performance of an Acid Gas Removal Unit (AGRU) installed on a floating gas production facility, thanks to a R&D program testing the influence of 3D motions and accelerations.
The accurate design of the Acid Gas Removal Unit has a great importance for the profitability and success of a FLNG project. In order to limit both weight and footprint, it shall rely on the lowest possible solvent flowrate and on the minimal and optimum equipment size to treat the feed gas while taking into account motions of the floating support. The proposed paper will demonstrate how a tight but safe design of an amine unit can be proposed thanks to the results of an extensive experimental program.
Total, Prosernat and IFPEN have conducted a four-year R&D program at Heriot-Watt University based on pilot tests aiming at modelization of mass transfer and hydraulics of tilting and moving towers. This program has included the testing of multiple parameters such as liquid/gas flowrates, liquid viscosity, diameter of towers, height of packing beds, packing efficiency. This has been done under various conditions: static tilt, pitch and 3D motions generated by a hexapod robot with six degrees of freedom. The motion conditions tested were similar to those experienced by a column installed on a floating gas production support or on a FLNG.
The collected information on hydraulics and mass transfer showed a significant impact of motions on liquid and gas distribution along the packing beds that can, under conditions of loads of gas and liquids, lead to a significant loss of absorption performances. An in-depth analysis of the large experimental data set with a comprehensive understanding of the phenomena in place allowed the development team to propose a robust model. This model is now embedded in a rated base mass transfer proprietary simulator of AGRU that can predict with good accuracy the impact of motions of the floating support on the performance of the unit.
This paper will present key results accumulated along the program about the impact of motions on liquid/gas maldistribution along a packing bed. It will explain how the accumulated knowledge enables to size tight but reliable AGRU's for installation on a floating support, in the presence of CO2, but also of other contaminants like H2S. The discussion will be supported by comprehensive examples of degradation of the absorption performances on real cases affected by sea motion.
A Study on the Accumulation and Distribution of Condensate Water in a CBM Field Gas Pipeline System
Authors: Guoxi He , Yongtu Liang , Jie Gao , Limin Fang , Liying Sun 
Published: November 2016

Abstract
This paper aims to determine the lowest pigging frequency and to reduce costs of pigging in CBM field gas pipeline system, by simulating the movement of water condensation in the dendritic gathering and transportation pipelines considering hydraulic and thermal character. The water content as a function of time and the distribution of liquid accumulated along the flow line have been simulated. As a result, optimized operation schemes have been proposed. Numerical model was established by considering the influence of temperature, pressure and terrain on gas flow and the saturated water content. The model which was validated by the PipePhase software contains three sub-models, namely the pressure drop model, the temperature drop model and the water film formation model. Then the migration model of water film was established to analyze the accumulation and distribution of condensate water depending on the flow rate and the terrain. Finally, the effects and sensitivity of decisive parameters on the amount of liquid were studied. And the precipitation and distribution of condensate water at the diameter-changing point were analyzed. Thus, total fluid volume and its distribution under different operating and environmental conditions were obtained. It was found that in the entire line, the liquid phase was mostly attached to the pipe wall by liquid film. The liquid film had a slight movement resulting from gravity and the carry of gas phase. Condensation occurred mainly in the first 1/3 length of the pipeline. At the end of the pipeline, the liquid stopped accumulating when the gas temperature kept constant and the pressure drop maintained. More condensate water and longer accumulation region were found in smaller diameter pipeline. And a significantly increased liquid holdup was also found in the diameter-reduced pipeline. Therefore, it is suggested that condensate tank or water drain valve or other facilities should be placed at the low-lying section in the first 1/3 length of the pipeline. The maximum acceptable pressure drop was taken as the target value to determine the longest pigging period under different working conditions. The liquid decreased gradually with the increase of inlet pressure, while with the decrease of temperature. The liquid volume is more sensitive to inlet temperature, and then ambient temperature, inlet pressure and flow rate. Thus it is suggested that the outlet pressure of compressor should be increased or an air cooling device should be installed.
Performance and Calculation Method of Steam Chamber Overcoming High Water Saturation Intervals during SAGD Process
Authors: Yang Renfeng , Zhang Jinqing , Yang Li , Chen Han , Tang Shasha 
Published: November 2016

Abstract
Many researchers study on the analytical model to predict chamber-to-reservoir interface shapes, production rates and oil-to-steam ratios during SAGD (Steam Assisted Gravity Drainage) process. But most studies are based on homogeneous reservoir models. Heat energy is transferred from steam to reservoir by conduction and convection, but heat transfer by convection is not considered in the classic SAGD mathematical models, especially when encountering the high water saturation intervals. And there was no analytical model or approach to analyze the performance of steam chamber overcoming high water saturation interval except the time consuming reservoir simulations.
The function of steam chamber rising height versus time was analyzed, thus the time duration before steam chamber invading the high water saturation intervals could be calculated. Then the relative roles of convective and conductive heat transfer at the edge of steam chambers were studied. A new calculation method was proposed to calculate the influence time of overcoming high water saturation intervals. According to the formation parameters, fluid properties and thermo-physical parameters, the influence time of overcoming high water saturation intervals could be predicted for other horizontal well-pairs, which has been proved to have high accuracy.
The newest significant finding is that convection can transfer a relatively large amount of heat at the edge of a steam chamber, but temperature increase because of convection is minor which could be neglected and the functional relation remains the same but the coefficient decreases. Meanwhile, a variable associated with vertical position of the high water saturation intervals is taken into account which could be obtained from the logging data. The value of the coefficient becomes smaller while the steam chamber invading high water saturation interval, because the high water saturation intervals rapidly halt the vertical growth of the steam chamber and spread the chamber laterally. The proposed method has been certified using temperature data from many wells and several reservoirs. The results demonstrated that the proposed new method works satisfactorily.
The novelty of the proposed method is in the ability to forecast the performance during steam chamber overcoming high water saturation interval in SAGD without time consuming reservoir simulations, which has been proved to have high accuracy.
Hydraulic Fracturing of Ultrahigh Stress Tight Oil Reservoir - A Case Study of Yumen Oilfield in China
Authors: Yi Peng , Dingwei Weng , Yun Xu , Liwei Wang , Yongjun Lu , Zhanjun Liu , Xiang Peng , Jiong Meng 
Published: November 2016

Abstract
This paper provides a case history of the first massive hybrid hydraulic fracturing in k1g1 tight oil formation of Yumen Field in China. Stimulating k1g1 formation is facing at least three difficulties: (1) deep depth (≥4700m TVD); (2) high treatment pressure(≥95MPa); (3)high fracture closure stress(≥100MPa), and fracture propagation gradient(≥0.0252MPa/m). There is oil and gas showing between 4640-5360m among wells in this region. These are tight sandstone highly laminated with mudstone, and the expected permeability was between 0.01 to 1mD, average porosity was 8.69%. The first a few stimulation treatments attempted in k1g1 formation nearly 10 years ago did not get good enhancement due to small stimulation volumes constrained by high treatment pressure and ultrahigh closure stress.
This paper analyzes the initial fracture treatment problems integrated with fracture modeling studies and provides a detailed discussion of formation characterization, rock mechanics, fracturing fluid and fracture design issues. And these studies were used to improve the stimulation strategy for future wells and help place more proppant volumes. Optimization of low-concentration HPG fracturing fluid (0.35%HPG, reservoir temperature≈110°C) and clay stabilizer were also conducted to reduce the damage to the formation which is more sensitive to it because of its low permeability and tiny pore throats. Proppant placement was achieved by using large volume slick water with multiple proppant-slug in low concentration and tailed in high concentration proppant with cross-linked gel fluid.
Yumen oilfield, as the pioneer in China's petroleum history (the first oil well was found there, so did the first well stimulated), is facing the huge challenge of production decline after almost 70 years’ continuous production. With the success of well CSL313 and CSL703, consequently k1g1 tight oil formation with 700m interval would be a good candidate for the succeeding resources. And the stimulation method described in this paper can be applied in other wells to ensure essential success of placing the designed proppant volumes and achieving aggressive stimulated intensity.
Successful Deployment of Tractor Conveyed Perforation in a Horizontal Well: Designing, Execution, Results and Lessons Learnt
Authors: Goenka S. K. , Goyal I. , Pandey N. , Kothiyal M. D. , Shah A. , Parasher A. , Vermani S. , Pinto T. , Nayak J. 
Published: November 2016

Abstract
Well X is a horizontal oil producer in AB-3 formation of the B field situated in the RJ-ON-90/1 block of Western India. Intervention in a horizontal well is inherently challenging, but the complex completion equipment of this well imposed additional challenges due to multiple ID changes along the well bore. The 8.5" OH section is completed with Inflow Control Device (ICD) screens and Swell Packers, middle completion consists of Packer and a Reservoir Control Valve (RCV) section set in the 9-5/8" production casing. Finally with 4.5" production tubing – and the production packer, upper completion was lowered but end of tubing was lying 8 m above the RCV section exposing 9-5/8" casing section also during any intervention.
After the initial completion when well was put online, it couldn’t flow naturally and was activated with nitrogen. Post activation it was observed that a well with 500 m of clean sand along the lateral section and productivity index (PI) of 150 b/d/psi was flowing with a PI of ~ 10 b/d/psi which also was not sustained and well was put on artificial lift. After attempting various stimulation techniques and correlating with offset wells, it was decided to perforate the screen section of the horizontal.
E-line conveyed Tractor assisted gun deployment system was selected to access the high angle well bore and perforate the screens. Apart from high deviation, the intervention unfriendly completion posed a major challenge to successfully RIH and POOH without a stuck tool or a tool lost-in-hole (LIH) situation. Extensive job planning, designing, and intervention modeling was completed before attempting the operation. The perforation job was carried out as a pilot test in 6 m of the 500 m OH section and resulted in ~ 1500 bopd of incremental oil in the initial well production. Analysis of the entire pilot project from the economics, technology and opportunity triangle, demonstrated the value of the technology and its usefulness in the future.
The paper endeavors to discuss the entire case while detailing the salient features like candidate selection, job designing and planning, challenges involved and lessons learnt during the successful execution of the intervention, also making it first of its kind horizontal perforation in the India. The learning and information shared will surely be useful in future to all such planned interventions into a high angle well especially during critical jobs like perforation.