bluuebunny/crossref_metadata_2025_split huggingface dataset:
Augmenting a Conventional Gas Lift System via Annulus Injection of Homogenized Foam and Gas: From Paper Plan to Execution
Authors: Kunasekaran Sarran Raaj , Ismail Syahezat , Yahia Zaidil , Naafs Derk , Koyyalamudi Lakshmi Narayana , Elias Noor Elfirdaous , Abu Bakar Azfar Israa , Ramba Akok , Othman Abdullah 
Published: October 2019

Abstract
BKR is a producing field, offshore Malaysia with almost 100 strings producing either naturally or utilizing gas lift as its primary artificial lift method. BKR being a mature field with increasing watercut production and declining reservoir pressures, experiences gas lifting issues such as an ever increasing lift gas demand and deteriorating lift gas utilization factor (GUF). To improve the gas lifting efficiency a pilot project utilizing foam to assist gas lifting was attempted.
Based on a literature studies, foam assisted gas lift is expected to be able to reduce the gas lift consumption by gas lifted wells, as well as further improving the lifting performance of gas lifted wells by introducing a foaming agent into the flow stream. After performing the feasibility studies, 2 wells were identified at BKR field for the pilot execution, based on the candidate screening criteria.
This paper presents the problems and opportunities which led to the foam assisted gas lift pilot trial in BKR field, as well as the trial results and key learnings. The theoretical background of the approach and few case studies done at other fields previously are summarized. It also details candidate screening criteria, chemical/foam lab tests to ensure foam performance and compatibility to the well system, evaluation approach, as well as potential application methods.
The second part of the paper discusses the planning and actual job implementation which includes logistics, treatment well on paper exercise, well and chemical surveillance plan and detailed treatment procedures.
The result of the pilot will be elaborated in detail in the paper covering the well's baseline production rate and production well test trends along the execution phase, pressure and temperature data collected, lessons learnt during pilot execution and potential way forward for the next pilot.
Based on the field trial results, the foam assisted gas lift approach has proven to be one of potential solutions to overcome gas shortage and poor GUF problems in the field. The results were very promising with almost a 100% improvement in production in one of the candidates. These results meet the goal of the pilot implementation which is to find a technology with good results with minimum expenditure. Nonetheless, several operational and logistic issues need to be addressed to have sustainable results, as well as prudent cost management.
Initiate Digital Oil Field Application at Mature Offshore Oil Field in South East Sumatera, Indonesia
Authors: Waskito Lucky Bagus , Vidrianto Marda , Cahyoniarso Bambang 
Published: October 2019

Abstract
In recent years the Industry are busy talking about the subject of mature field development, lots of opportunity and approaches has been applied to enhanced reserves and production, in the other hand efficiency and technology also can be the answer of the subject, big volume of data at high frequency produced every second, searching relevant information from those data are quite complex and time consuming, not to mention processing huge data volume for many particular solution, it is complicating the decision making process. The objective of this paper is addressing the process and technical challenges in building digital oil field platform at offshore mature asset to speed up the decision making and make operation activities more efficient.
The design of the workflows and business processes are tailored to accommodate any kind of input across all the disciplines from reservoir, production, drilling and completion to produce output as desired. The early stage process of building digital oil field system starts from data utilization that produced by downhole sensors, it is attached with Electric Submersible Pump that installed at all wells. The data transformed into information for real-time production monitoring & optimization, these workflows allow production enhancement by continuous monitoring of production parameters such as pressure, temperature, flow rates, choke settings and target. Analysis of these parameters carried out using trend, in case of anomalies happens in the process, the system will provide the information and possible solution.
Digital Oil Field technology can be a game changer for the mature field development in the future. Integration of technology, process and people together to achieve financial objective is the major initiative of digital project, but applying digital technology is easier said than done as our companies are finding out, in our case we faced several difficulties that need time and complex algorithm to find the solution. But this early stage of digital oil field will answer the challenges in managing offshore mature asset efficiently, because it will reduce downtime, optimize production, and reduce cost. The future development of digital oil field in SES Block will allow all parties to grab the information in present time and also the forecast prediction of asset performance in the future.
SES Block is a mature oil field that has produced for more than 50 years, peak production rate almost reached 250,000 BOPD in 1991, while current production rate around 30,000 BOPD. One of the major problems in this asset is the excessive use of Electric Submersible Pump that generates high operating cost, this is the reason why efficiency during daily operation process using digital oil field application is smart answer to reduce cost and optimize company profit.
Comprehensive Study of the Oda Corrected Permeability Upscaling Method
Authors: Haridy Mohamed Galal , Sedighi Farzaneh , Ghahri Panteha , Ussenova Kamshat , Zhiyenkulov Murat 
Published: October 2019

Abstract
Choosing an appropriate technique for upscaling the permeability of the discreet fracture network (DFN) model is vital for maximizing recovery from naturally fractured reservoirs (NFR). Flow -based upscaling is accurate, yet it is computationally expensive. Analytical (i.e. Oda method) upscaling is computationally efficient; however, it is only accurate for well-connected fractures. The objective of this paper is to analyze the performance of the newly developed Oda corrected method which addresses issues associated with previous upscaling methods.
This research was executed by using a commercial numerical simulator and by using data set from the Teapot Dome Reservoir. Furthermore, DFN modeling was used to generate different realizations for the fracture network. Consequently, sensitivity analysis was performed through a realisti c uncertainty quantification to generate a base case and 6 different DFN realizations. The main parameters used for this study are fracture length and intensity. Afterwards, the fracture permeability corresponding to each DFN realization was upscaled using the above-mentioned methods. Finally, differences between the upscaling methods were evaluated and analyzed using flow-based upscaling as the criterion.
Indeed, the analysis revealed that the new Oda corrected method can calculate the equivalent permeability tensor with adequate accuracy. However, it overestimates the permeability when fracture networks are below the percolation threshold and/or when fractures length is large. Hence, this method is recommended for networks with moderate to high intensity. Furthermore, it has been deduced that fracture length has a great impact on the connectivity of fractures, albeit its effect on permeability is limited by fracturing density. Additionally, it has been found that the length of fractures has an immense impact on the anisotropy ratio and control the occurrence of water bypassing, which were not captured by the Oda method.
Comparative Evaluation of the Effectiveness of Single-Component and Multi-Component Hydrocarbon Additives for Bitumen Recovery by Steam Assisted Gravity Drainage
Authors: Selvakumar Bhuvanesh , Gates Ian , Maini Brij 
Published: October 2019

Abstract
The inherently high viscosity of bitumen makes SAGD the ideal technology for in-situ recovery of these unconventional hydrocarbon deposits. Its conceptual simplicity and proven performance in the field have directed research to explore new opportunities to further improve its recovery efficiency and minimise its environmental footprint. Solvent addition to steam in a SAGD process makes the thermal and solvent dilution effects on oil viscosity act together in improving the bitumen recovery. Various experimental, numerical and pilot studies have shown the incremental benefit of solvent co-injection in accelerating the oil recovery at reduced steam-oil ratio compared to steam alone injection. The objective of this work was to evaluate the effectiveness of different single-component and multi-component additives for improving the SAGD performance.
Among the various process variables, the optimal solvent design and the injection pressure play influential roles in determining the process efficiency, as they directly affect the phase behavior of the system. This paper uses numerical simulation to examine the solvent-SAGD mechanisms and presents a comparative analysis of single and multi-component solvent injection at low and high operating pressures. A lab scale physical model saturated with Athabasca bitumen, used in an earlier experimental study, was adapted to a simulation model for this purpose. After tuning the numerical model by history matching the physical model experiments, it was used to compare the benefits of co-injecting different solvents with steam at two different operating pressures. A range of single component solvents (C4, C5 and C6) and a multi - component gas condensate were aevaluated for low and high-pressure injection scenarios.
The results show that all tested solvents reduce the steam oil ratio and enhance the rate of oil production. The relative performance of different solvents is affected by the innate bitumen viscosity and the operating pressure. With lower bitumen viscosity, C4-steam co-injection outperformed C5, C6 and gas-condensate addition for both low- and high-pressure ES-SAGD cases. However, the performance of heavier solvents was better at higher operating pressures due to their relative ease of condensation, which enhances their interactions with bitumen.
Acquiring Offshore Project Sanction during Low Oil Price Environment: Rejuvenating Reservoir with Depleted Reservoir Energy via Innovative Low Capex Gas Injection Project
Authors: Awang Pon M Zaim , Hongmei Gao , Chee Hui Sim , Abdul Aziz Shahrizal , Abdulhadi Muhammad , Van Tran Toan , Anuar M Azlan , Jacobs Steve , Munandai Hasim , Khalid Aizuddin , Kumar Ashok 
Published: October 2019

Abstract
Maturing a secondary recovery project in an offshore multi-fault complex reservoir is challenging because considerable investment is required, especially in a low oil price environment and/or when the asset can no longer produce. However, an 85% reduction in cost with no reduction in reserves was achieved for such a reservoir through de-risking the opportunity and revising the development concept, allowing the project to be sanctioned during a low oil price environment.
A water injection project with an estimated cost of 165 MMUSD was initially envisaged during the feasibility stage to increase the oil recovery of a depleted reservoir, and contractual expectations were agreed accordingly. This is due to the availability of seawater offshore and water injection being the standard improved recovery approach in the region. Without adhering to the familiarity, a reservoir simulation study was performed comparing multiple options of secondary recovery. The reservoir simulation indicated that gas injection would provide higher incremental recovery while the investment can be significantly reduced by utilizing the existing gas lift system as a gas injection system.
Several improved oil recovery schemes were evaluated with the history matched dynamic model to address the depleted energy. This includes water dumpflood, water injection, and gas injection with recovery factors of 32%, 56%, and 58%, respectively, in comparison to the depletion drive recovery factor of 30%. The gas injection scheme provides the highest recovery factor and expected fastest response and thus was prioritized as the main focus over water injection. The existing gas compressor with ullage, gas source from current associated gas production, and existing idle wells are key enablers for the project. The existing assets also enable the acceleration and further de-risking by a pilot gas injection before drilling infills.
The paper highlights the numerous examples of cost-saving initiatives while maximizing the oil recovery from the reservoir. This value-focused approach enabled the project to be sanctioned during a period where most offshore improved recovery projects were abandoned due to the low oil price.
Sustainability Initiative: Integrating Environment and Social E&S Requirements into a Front End Loading FEL Management System
Authors: Asmoro Trian Hendro , Prabowo Hirmawan Eko , Prayascitra Adearty 
Published: October 2019

Abstract
All project requirements should completely be defined in the planning phase, thus it seen as the most critical activity in a project’s lifecycle. Sustainability aspects for an Exploration & Production (E&P) project need to be included starting from planning phase to identify and manage project risks particularly in Environment and Social (E&S) sides. In fact according to a study, some key principles of sustainability have actually been adopted in the E&P activities.
Meanwhile, Front End Loading (FEL) is a structured approach to increase the predictability of the project outcomes by narrowing down the risks from all technical, commercial, legal, E&S and other aspects. It uses a stage gate system in order to assure the project prior to authorization and to move on to the next step of investment decision, and a typical FEL method has widely implemented in the E&P business across the globe using different company name.
One of set of requirements addressing sustainability aspects in a project is that Performance Standards (PS) developed by IFC (International Finance Corporation). It has 8 comprehensive elements and internationally-accepted standard of E&S practices which encourages transparency and positive contribution to environment and community. In addition, adopting IFC PS has been mostly becoming compulsory nowadays when dealing with financial institutions to support a project financing to be considered as green financing.
This paper will explore how to integrate E&S requirements taken from IFC PS, such as E&S Impact Assessment (ESIA) and E&S Management System (ESMS) into a FEL management system for an E&P company operated in Indonesia. It will discuss the gaps between sustainability features in IFC PS and Government regulation, and finally bridge them properly. To conclude, it is very important to include sustainability requirements earlier in the project’s lifecycle to help manage E&S risks in the project and improve the outcomes.
Reservoir Productivity Assessment Using Advanced Formation Evaluation, Image Logs and Formation Testing and Sampling Methods: A Case Study
Authors: Firdaus Iman , Gultom Luhut , Sadat Anwar , Negara I Made , Yusuf Hotma , Harfoushian Jack , Juandi Dedi , Adeyosfi Merza , Sudarwoto Rinaldi , Wibowo Febrian , Herianto Bambang , Hartanto Rudi 
Published: October 2019

Abstract
Saka Indonesia's primary objective of drilling an appraisal well offshore North-East Java was to accurately assess productivity of the three main reservoirs discovered by the exploration well drilled in the Pangkah Block. This paper details the integration of advanced formation evaluation procedures and interpretation of image logs with novel formation testing methods, which were used to plan and optimise drill stem tests (DST) conducted across the three reservoirs.
Deployed on wireline, formation evaluation and electrical borehole image logs were acquired in open hole of the exploration well. Nuclear magnetic resonance (NMR) and image logs were processed simultaneously in near real time to facilitate the planning of the subsequent formation pressure testing and fluid sampling program. Using the recently introduced advanced formation testing technology, reservoir deliverability was accurately established, in addition to characterising fluids insitu and obtaining reservoir fluid samples.
Interpreted results of data acquired on wireline from different logging runs were integrated and consequently used to optimise the well testing program across the intercepted heterogeneous and low permeability limestone reservoirs. In addition to determining porosities, free fluid volumes and the range of permeabilities, Drill Stem Test (DST) zones were confidently defined using the free water levels ascertained by constructed vertical pressure profiles. As a result, DST measurements matched the permeability and productivity estimations across the three pay zones.
The integrated approach of formation evaluation, textural analysis and permeability and productivity measurements enabled the evaluation of three complex limestone reservoirs discovered in this field, which included secondary porosities and interconnected vugs. These results were ultimately verified and confirmed by the well tests conducted across the three reservoirs.
From Data Collection to Data Analytics: How to Successfully Extract Useful Information from Big Data in the Oil & Gas Industry?
Authors: Al-Alwani Mustafa A. , Britt Larry K. , Dunn-Norman Shari , Alkinani Husam H. , Al-Hameedi Abo Taleb , Al-Attar Atheer M. , Alkhamis Mohammed M. , Al-Bazzaz Waleed H. 
Published: October 2019

Abstract
Big data has become a major topic in many industries. Most recently, the oil and gas industry adopted a special interest in data science as a result of the increasing availability of public domains and commercial databases. Utilizing and processing such data can help in making better future decisions. The aim of this work is to provide an example and demonstrate methodologies on how to collect and utilize big data to help in making better future decisions in the oils and gas industry.
After reading a good number of papers and books about the applications of data analysis in the oil and gas industry, in addition to other industries, and given that data analysis is the area of expertise of the authors, this paper was written to demonstrate real examples of data processing and validation workflows. This work is intended to cover the gaps in the literature were many of the publications only discuss the importance of data-driven analytics.
This paper provides an overview of the diverse and bulk data generating sources in the oil and gas industry, starting from the exploration phase to the end of the lifecycle of the well. It provides an example of utilizing a public domain database (FracFocus) and demonstrates a step by step workflow on how to collect and process the data based on the objective of the analytics. Two real examples of descriptive and predictive analytics are also demonstrated in this paper to show the power of having a diverse and multiple resources databases. A framework of data validation and preparation is also shown to illustrate data quality checks combined with best practices of data cleansing and outlier detection methodologies.
This paper provides a clear methodology on how to successfully apply data analysis which can serve as a guide for some future data analysis applications in the oil and gas industry.
Reservoir Performance Benchmarking to Unlock Further Development of Malaysian Oil Fields
Authors: Ranjan Rakesh , Rizal Mas , Soni Sumit , Masoudi Rahim , Souche Laurent 
Published: October 2019

Abstract
As resource owner and enabler, PETRONAS's Malaysia Petroleum Management (MPM) is entrusted to ensure maximizing recovery efforts from more than 1000 oil reservoirs under production in its portfolio. Performance and recovery from oil reservoirs depends on many factors that can be broadly classified into Reservoir Complexity and how the reservoir has been developed and managed. To undertake a development gap analysis and expectation setting the exercise was undertaken to benchmark reservoir performance against reservoirs of similar complexity. The objective was to take the learnings from better performing reservoirs and explore potential replication in poor performing reservoirs of similar complexity. The main challenge was to establish a single term to define Reservoir Complexity. This term should encompass all the factors like geological, petro physical, rock & fluid etc. that could potentially make the reservoir complex and at the same time also decide on the relative weightage of these parameters posing recovery challenges. Data analytics has been used to accomplish this task and the calibration with reference reservoirs has been achieved. This benchmarking tool can help to internally set targets for all fields where the recoveries have been lower than normally observed, help set EUR numbers for green fields and drive additional development strategies to maximize recoveries in existing fields where they are falling short.
When reservoirs of similar complexities are grouped together, they show varying performance indicators viz. recovery factor, decline rates etc. The gap analysis between the reservoirs of similar complexity has helped in identifying poor performing reservoirs and the underlying reasons for underperformance. Learnings from the better performing reservoirs have been incorporated and a detailed action plan has been prepared to improve the performance of these reservoirs. Considering the various ways in which this information can be used, a reservoir complexity benchmark would be a great asset to any major operator or regulator.
The workflow has been developed to calculate complexity based on the parameters that are affecting microscopic displacement efficiency, horizontal displacement efficiency and the vertical displacement efficiency. Data analytics has been used to assign weightages to each component posing recovery challenges and derivation of a single number defining complexity on a scale of 0 to 1. This is major improvement on all previous works of this nature attempted in various parts of the world and provides the user with not only the complexity per se but also its distribution. This benchmarking tool has been used for selected fields and has enabled development gap analysis and helped in initiating course correction to unlock more values from the underperforming reservoirs.