bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Heat Treatment to Prevent Fracturing Fluid-Induced Formation Damage and Enhance Matrix Permeability in Shale Gas Reservoirs
Authors: Chen Mingjun , Li Peisong , Kang Yili , Gao Xinping , Yang Dongsheng , Yan Maoling 
Published: October 2021

Abstract
The low flowback efficiency of fracturing fluid would severely increase water saturation in a near-fracture formation and limit gas transport capacity in the matrix of a shale gas reservoir. Formation heat treatment (FHT) is a state-of-the-art technology to prevent water blocking induced by fracturing fluid retention and accelerate gas desorption and diffusion in the matrix. A comprehensive understanding of its formation damage removal mechanisms and determination of production improvement is conducive to enhancing shale gas recovery. In this research, the FHT simulation experiment was launched to investigate the effect of FHT on gas transport capacity, the multi-field coupling model was established to determine the effective depth of FHT, and the numerical simulation model of the shale reservoir was established to analyze the feasibility of FHT. Experimental results show that the shale permeability and porosity were rising overall during the FHT, the L-1 permeability increased by 30- 40 times, the L-2 permeability increased by more than 100 times. The Langmuir pressure increased by 1.68 times and the Langmuir volume decreased by 26%, which means the methane desorption efficiency increased. Results of the simulation demonstrate that the FHT process can practically improve the effect of hydraulic fracturing and significantly increase the well production capacity. The stimulation mechanisms of the FHT include thermal stress cracking, organic matter structure changing, and aqueous phase removal. Furthermore, the special characteristics of the supercritical water such as the strong oxidation, can not be ignored, due to the FHT can assist the retained hydraulic fracturing fluid to reach the critical temperature and pressure of water and transform to the supercritical state. The FHT can not only alleviate the formation damage induced by the fracturing fluid, but also make good use of the retained fracturing fluid to enhance the permeability of a shale gas reservoir, which is an innovative method to dramatically enhance gas transport capacity in shale matrix.
Field Optimization Via Data Approach: A Case Study of Data Mining for Tight Gas Flowback Evaluations
Authors: Liu Yuan , Li Bin , Zhang Hongjie , Yang Fan , Wang Guan , Wang Weikan , Zhao Jinyu 
Published: October 2021

Abstract
The economics of tight gas fields highly depend on the consistency between expected production and the actual well performance. A mismatch between the reservoir quality and the well production often leads to a review of the individual well. However, such mismatch may vary from case to case, and it is hard to perform a field-level analysis based on individual well reviews. We introduce a new method based on data mining to assist the field-level diagnosis.
LX gas field is located the in eastern Ordos basin. Compared to the main gas field in the center of the basin, LX field is less predictable in well performance. This predictability issue hinders field development in LX field because the field economics are substantially jeopardized by the inconsistency between the reservoir quality and the production performance.
The traditional workflow to understand this issue at the field level is to review the details of a large number of individual wells in the area. This is typically an intense task, and too much detail from multiple disciplines may hide the true pattern of the field behavior. To resolve this issue, we applied data mining in our field development diagnosis workflow.
Our new workflow in LX area started with the existing field datasheet, including logging summaries, completion treatment reports, and flowback testing datasheets. With the data extracted from these different sources, we visualized the consolidated information in various plots and graphs based on regression analysis, which revealed the relation between flowback ratio and the production, the flowback rate consistency from the different service suppliers, and the impact of water productions.
The data mining approach helped to generate new understandings in LX gas field. With the in-depth analysis of the flowback data together with reservoir properties and operation parameters, the key problems in the field were identified for further development optimization, and the field economics can be significantly improved. The diagnosis method can be easily adapted and applied to any field with similar problems, and data mining can be useful for almost all large-scale field development optimizations.
Reserves and Resources Management: A Continuous Improvement of the Business Processes
Authors: Hadi Aen Nuril , Leonardo Stephen , Anwar Khairul , Aritonang Tuan Manotar , Dewi Devialina Puspita , Fatimurakhman Fery , Hamza Bayu , Adma Alfariko 
Published: October 2021

Abstract
Managing oil and gas reserves and resources of Pertamina, an Indonesia state owned energy company, has always been challenging processes as the company's portfolio is sparsely located throughout Indonesia. Moreover, since November 2013 the company has also managed its international assets spread across three regions, namely Africa, Asia, and Middle East. In total, there are ~480 fields and ~870 geological structures with different degree of geological background, environment, uncertainty, and maturity of the fields/projects. Obviously, to cope with all those complexities, Reserves Management Department need to figure out its way to properly manage reserves and resources of the company.
Reserves and resources of oil and gas is a key strategic priority of the company. It is aligned with both portfolio management and development and production of the assets. Company decision in terms of work program and budget is also mainly derived from reserves and resources potential of the projects. Therefore, to obtain a standardized reserves and resources management, the company has launched company guideline which is mainly influenced by SPE Petroleum Resources Management System (SPE-PRMS, 2007). SPE-PRMS is a project-based system, where reserves and resources estimation, categorization, and classification are on project basis. To properly manage all the projects, since 2019, Reserves Management Department introduced a tool named Project Box which enable reserves analyst to properly map all the projects, evaluate the portfolio, and monitor the progress of the project both in development and exploration phase. Furthermore, to be aligned with company's digitalization campaign, all the reserves and resources data, Project Box, and many other strategic information are stored and maintained in an in-house software named Promyst which will be launched in early 2021. This tool will enhance data accessibility for both management and analyst, increase data integrity and security, provide data analysis platform, moreover this software could also generate cost efficiency for the company.
In 2017, along with the final version of the company guideline, the company has fully adapted PRMS. This paper will explain how the company adapt PRMS to its company guideline in which some necessary adjustments took place with respect to company's business processes, the application of Project Box throughout all company's subsidiaries, and implementation of Promyst along with its features and future projection of the software. The result and benefit of implementing those items will be explained in this paper. These extensive works performed by the Reserves Management Department contribute significantly to the company not only for technical but also for commercial aspects therefore promoting a good corporate strategic planning and decision making.
Success Deployment and Operation of Downhole Casing Valve Improves Tripping and MPD Operation While Saving 5 Drilling Days Through Total Loss Circulation in Basement
Authors: Joydi Zein Mirza , Fikri Irawan , Sekar Dewayani Wuri , Andry Prasthio 
Published: October 2021

Abstract
Southern part of Sumatra is known for its high deliverability hydrocarbon gas formation with flow rate up to 200 MMSCFD produced from a single well. The fractured network present mainly in its granite basement formation posed as the primary hydrocarbon contributor aside to the carbonate zone. High formation pressure with massive gas reservoir as its driving mechanism combined with total loss circulation due to geological fault in the same section, lead to operation with various hazard combined which demands potent solution. Advanced technologies required to execute the operation in safest and efficient manner.
Downhole Casing Valve (DCV) is one of Managed Pressure Drilling (MPD) equipment used to support operation with deep and high-pressure formation, installed alongside with casing to provide sealing of the well at depth. Equipped with flapper type valve and full borehole size, DCV which is surface controlled, enables operator to seal the well in the absence of any string. The seal created by DCV allows the string to be pulled out preventing to kill a live well.
The South Sumatra blocks depicts enormous potential gas reservoir. Located in the fault of basement where total loss circulation will occur in highest probable manner. Utilization of chemical mixed mud was impractical considering the total loss circulation. Thus, pressure exerted from fluid column and pumping flow rate from string needs to be compensated by surface backpressure. In addition, to accommodate deep footage penetration of the section, hard basement formation, complex completion running sequence, and multiple tripping for BHA changes, requirement of DCV shifted from nice-to-have into a must-have segment. Without the need of killing the well nor changing the mud system, DCV allows tripping operation to be completed safely and efficiently by sealing the well with its flapper, saving costs and time on each tripping operation. DCV utilization successfully supports drilling high-pressure gas reservoir through basement fault until target depth reached safely and efficiently.
Troubleshooting Cable Deployed Thru Tubing Electrical Submersible Pumps: A Case Study from South East Asia
Authors: Anand Saurabh , Rosland Eadie Azahar B , Ghonim Elsayed Ouda , Riyanto Latief , Abu Bakar Khairul Azhar B , Mohd Radzuan Nurul Asyikin Bt , Mat Khair Nusheena Bt , Zaki Shazana M 
Published: October 2021

Abstract
PETRONAS had embarked on an ambitious thru tubing ESP journey in 2016 and had installed global first truly rig less offshore Thru Tubing ESP (TTESP) in 2017. To replicate the success of the first installation, TTESP's were installed in Field – T. However, all these three TTESP's failed to produce fluids to surface. This paper provides the complete details of the troubleshooting exercise that was done to find the cause of failure in these wells.
The 3 TTESP's in Field – T were installed as per procedure and was ready to be commissioned. However, during the commissioning, it was noticed that the discharge pressure of the ESP did not build-up and the TTESP's tripped due to high temperature after 15 – 30 mins of operation. Hence none of the 3 TTESP's could be successfully commissioned. Considering the strategic importance of TTESP's in PETRONAS's artificial lift plans, detailed troubleshooting exercise was done to find the root cause of failure to produce in these three wells. This troubleshooting exercise included diesel bull heading which gave some key pump performance related data.
The three TTESP's installed in Field – T were of size 2.72" and had the potential to produce an average 1500 BLPD at 80% water cut. The TTESP deployment was fully rigless and was installed using 0.8" ESP power cable. The ESP and the cable was hung-off from the surface using a hanger – spool system. The entire system is complex, and the installation procedure needs to be proper to ensure a successful installation. The vast amount of data gathered during the commissioning and troubleshooting exercise was used for determining the failure reason and included preparation of static and dynamic well ESP model. After detailed technical investigative work, the team believes to have found the root cause of the issue which explains the data obtained during commission and troubleshooting phase. The detailed troubleshooting workflow and actual data obtained will be presented in this paper. A comprehensive list of lessons learnt will also be presented which includes very important aspects that needs to be considered during the design and installation of TTESP. The remedial plan is finalized and will be executed during next available weather window.
The key benefit of a TTESP installation is its low cost which is 20% – 30% of a rig-based ESP workover in offshore. Hence it is expected that TTESP installations will pick-up globally and it's important for any operator to fully understand the TTESP systems and the potential pain points. PETRONAS has been a pioneer in TTESP field, and this paper will provide details on the learning curve during the TTESP journey.
Proven Technologies and Solutions for Successful Production Enhancement in Malaysia with Array Production Logging
Authors: Vevakanandan Valsan , Ting Angelina Jia Hui , Kho Sze Fong , Ho Chen Nyap , Tan Aaron Qun Jie , Manzar Muhammad Abrar , Lim Eng Chuan 
Published: October 2021

Abstract
M field is a faulted anticline structure that lies in a deepwater turbidite environment. Field Development started in late 2016, with 10 oil producers and 2 water injectors. Within 2 years of production, significant GOR increase in some of the wells led to production curtailment, which has impacted the field production promise. Poor injectivity seen in one of the water injectors also led to an assumption of compartmentalization or sandface plugging/damage that required investigation. In order to evaluate intervention opportunities to mitigate against the high GORs and to determine the cause of the poor injectivity, production logging tools were proposed in four candidate wells.
The objectives of the logging campaign were:
To understand the gas influx profile into the well and how different compartments are contributing to the GOR Assess behaviour of G/O, O/O, O/W crossflows and their impact on reservoir depletion profile Aid decisions in requirements for downhole controls (i.e. AICD placement) vs surface controls Provide opportunity to couple PL logs with PNC logs to identify potential GOCs, estimate gas/water saturations and determine if there are any bypassed oils
Based on the candidate wells, the following challenges were present:
Highly-deviated/horizontal wells requiring complex conveyance solutions Multiphase flows (gas, oil and potentially water) in highly deviated conditions which further complicates fluid phase contribution calculations and velocity modeling Rig up height limitations on the platform which requires shorter logging tool strings High flowrates with tool lift limits requiring careful modelling work to ensure risks are understood and minimized
In view of these challenges, a new Array Production Logging Tool (henceforth called New-APLT) was proposed as an alternative to the previous generation APLT. It has a more robust design with co-located sensors in a single module with additional optical sensors that improves flow measurement and gas detection.
Additionally, screen tracers sampling was proposed in one well, which would help calibrate the tracer interpretations against actual fluid rates. The novel approach and synergistic efforts amongst many disciplines led to a successful execution of the logging campaign, and the first ever deployment of the New-APLT tool on e-line tractor. The timely results from the campaign which coincided with a 4D seismic acquisition has helped to justify downhole control options for some of the wells, and potentially helped to avoid costly remedial work on the water injector. The valuable dataset will also influence the infill development well campaign location, design and well count.
Drilling and Completion Waste Reutilization and Zero Discharge Technology Used in China Bohai Bay
Authors: Wang Kunjian , Liu Pengfei , Hou Xinxin , Wang Pan , Zhu Pei , Hao Mingxuan , Li Dejiang , Tang Qisheng , Wang Qing , Ge Wenchen , Zeng Xu , Zhang Hao , Zhang Shihao , Chen Kejin 
Published: October 2021

Abstract
With the increasingly stringent national environmental rules, waste produced in drilling and completion process is forbidden to be discharged into the Bohai Bay or reinjected into the formation. The current disposal method of drilling and completion waste in Bohai Oil field has some problems such as high cost, low efficiency and high HSE management and control risk. Faced with these problems, drilling and completion waste reutilization and zero discharge technology has been developed and applied in this region.
In order to reutilize drilling and completion waste which include cuttings circulated from formation, wasted drilling and completion fluids, the following aspects are carried out: Firstly, drilling platform is upgraded to meet the zero discharge requirement: solid control system is modified, cuttings closed transfer system and cuttings treatment system are equipped on the platform to collect and dispose the waste. Meanwhile, recovery and disposal capacity to support different spud drilling are assessed: cuttings transport capacity is up to 15m3/h, which can meet the highest requirements of 12-1/4″ hole drilling when ROP is up to180m/h. Secondly, the well profile is downsized to reduce the production of cuttings, mud and other wastes from the root, which can also improve efficiency and yield cost.
The field application shows that the amount of the waste has been reduced by 41.39%, 39.86% and 41.52% in first, second and third spud drilling, and average ROP is 35%, 28%, 42% higher than similar wells drilled before. Lastly, in drilling and completion fluids system optimization and reutilization aspects, environmentally friendly drilling and completion fluids with low solid content are developed. The experiment shows that the properties of the liquid phase after solid-liquid separation can be reused, and the solid phase with low water content is easy to pack and transport back to land.
Drilling and completion waste reutilization and zero discharge technology introduced in this paper has been successfully applied in more than 40 wells, and the volume of waste drilling fluid is reduced by 80%, which is a trade-off between zero discharge and well construction cost. This technology can also be applied in other offshore oilfield which is inevitable as the environmental rules become more and more strict.
Novel Approach for Selecting Well Candidates and Appropriate Design of Hydraulic Fracturing in Challenging Reservoirs
Authors: Mirza Muhammad , Saadi Hassan Al , Trejo Ricardo Sebastian , Kayumov Rifat , Hilal Ahmed 
Published: October 2021

Abstract
Karim and Haradh reservoirs within the Karim Small Fields (KSF) cluster in the South of the Sultanate of Oman are characterized by low to medium permeability and significant heterogeneity and contain medium to heavy crude oil. Reservoir depths are in the range of 1500 to 2000 m and productive areas are relatively small (around 2 km2 per field).
Over the past 10 years, fields development did not result in sustained oil production despite the close well spacing. Geological and reservoir studies indicated that this is mainly due to the heterogeneity, lack of reservoir continuity and presence of significant wellbore damage in most wells. Accordingly, the KSF operator initiated an appraisal campaign focusing on hydraulic fracturing to stimulate the producing wells and improve the extension of their drainage areas. This campaign resulted in significant improvement in well productivity and the analysis of results indicates good potential for improving the ultimate oil recovery from these reservoirs.
Although the results from hydraulic fracturing campaign are encouraging, they also indicate that appropriate selection of well candidates, key parameters in the fracturing procedure, effects of well completion and impact of well age are very important for successful oil gain. As a result, a comprehensive procedure for selecting and ranking candidate wells for hydraulic fracturing in Karim and Haradh formations has been developed. The procedure includes assessing the impacts of key properties such as fracture height, depth of oil-water contact, thickness of oil column, and distance to faults. In addition, the lessons learned from the previous appraisal campaign will contribute to achieving optimum fracture geometry in future campaigns.
The candidate selection workflow involves understanding the geology, geomechanics, and petrophysics of the wells in which a fracturing operation was performed previously in different formations in KSF. More than 20 existing wells were screened through the candidate selection process using a clear workflow to incorporate all the relevant aspects of the selection criteria. The outcome of the candidate selection phase led to selection of the best wells for fracturing operations in the Karim and Haradh formations. The improvements on the fracturing design have been followed to obtain the optimum fracturing design for the selected wells.
Practical Considerations when Using Capacitance Resistance Modelling CRM for Waterflood Optimization
Authors: Simha Srungeer , Ujjwal Manu , Modi Gaurav 
Published: October 2021

Abstract
Capacitance resistance modeling (CRM) is a data-driven analytical technique for waterflood optimization developed in the early 2000s. The popular implementation uses only production/injection data as input and makes simplifying assumptions of pressure maintenance and injection being the primary driver of production. While these assumptions make CRM a quick plug & play type of technique that can easily be replicated between assets they also lead to major pitfalls, as these assumptions are often invalid. This study explores these pitfalls and discusses workarounds and mitigations to improve the reliability of CRM.
CRM was used as a waterflood optimization technique for 3 onshore oil fields, each having 100s of active wells, multiple stacked reservoirs, and over 15 years of pattern waterflood development. The CRM algorithm was implemented in Python and consists of 4 modules: 1) Connectivity solver module – where connectivity between injectors and producers is quantified using a 2 year history match period, 2) Fractional Flow solver module – where oil rates are established as a function of injection rates, 3) Verification module – which is a blind test to assess history match quality, 4) Waterflood optimizer module – which redistributes water between injectors, subject to facility constraints and estimates potential oil gain. Additionally, CRM results were interpreted and validated using an integrated visualization dashboard.
The two main issues encountered while using CRM in this study are 1) poor history match (HM) and 2) very high run time in the order of tens of hours due to the large number of wells. Poor HM was attributed to significant noise in the production data, aquifer support contributing to production, well interventions such as water shut-offs, re-perforation, etc. contributing to oil production. These issues were mitigated, and HM was improved using data cleaning techniques such as smoothening, outlier removal, and the usage of pseudo aquifer injectors for material balance. However, these techniques are not foolproof due to the nature of CRM which relies only on trends between producers and injectors for waterflood optimization. Runtime however was reduced to a couple of hours by breaking up the reservoir into sectors and using parallelization.