bluuebunny/crossref_metadata_2025_split huggingface dataset:
Smart Segmented Polymer Injection Pilot: A Case Study
Authors: Sun Fuchao , Pei Xiaohan , Gai Xubo , Sun Shuang , Hu Shifeng 
Published: October 2021

Abstract
Polymer flood is proved an effective method for EOR in China. Traditional segmented polymer injection technique cannot obtain continuous layer parameters. Real-time monitoring is necessary for polymer flood because downhole pressure and flowrate vary more often than waterflood. Existing technique for layered monitoring and flowrate adjustment is wireline test. There is no smart technique which can realize real-time monitoring and automatic flowrate control. In this paper, a smart segmented injection technique for polymer flood well is introduced. A smart distributor is permanently placed in each layer. It is composed of flowmeter, temperature sensor, two pressure sensors, downhole choke and electrical control unit. The special flowmeter is adopted for polymer flowrate test. All the distributors are connected together by a single control line which is set outside of the tubing string. Operator can read the data of each layer and adjust the flowrate whenever needed at any time which makes the technique a smart one. The smart technique for polymer flood wells has been implemented in a polymer well in Daqing oilfield of China. A case study for smart segmented polymer injection pilot is introduced in detail including technical principle, indoor test results, construction process and adjustment process. The application results show that the operator on the ground can easily obtain downhole tubing pressure, layer annulus pressure, temperature and flowrate on line. The sample time can be set to any one between 1-65536s according to geological engineer's advice. There is no limitation caused by battery power because the distributor is powered by cable on the ground. In terms of adjustment, the flowrate can be adjusted according to the target value. And it can also be regulated at any time manually, just needing pushing the mouse in the office. The application also displays that the smart segmented technique has the advantage for polymer injection because of larger change of layered parameters. It can provide more real-time data for oil development engineer and the data are beneficial for better understanding and optimization of the reservoir. Therefore, the smart segmented polymer injection has a great potential for EOR based on polymer flood.
A Novel Approach to Evaluate Deliverability of Gas Wells with Pressure Fluctuation
Authors: Zhang Yongbin , Sun Xiongwei , Bai Xiaojia , Jia Wei , Zhu Bo , Wang Haibo 
Published: October 2021

Abstract
Majority of gas fields in Tarim Basin are HPHT (high-pressure/high temperature) reservoirs with buried depth more than 5000m. The special geological conditions made it a challenge for underground well testing due to safety issues. Additionally, wellhead pressure fluctuation is widely existed both from geological and engineering factors, including sand production, well casing integrity problems, contamination of downhole fracturing fluid and wax deposition in wellbore etc. Traditional deliverability evaluation method which relies on underground well testing is greatly limited as it is not capable of reflecting the dynamic change of gas well deliverability due to abnormal wellhead pressure fluctuation.
In this study, a new approach is proposed to evaluate the deliverability of these kind of wells using dynamic data from wellheads. An apparent and a potential deliverability curves are based on binomial deliverability equation are established individually according to whether the additional skin caused by wellbore blockage is taken into consideration. The variation characteristic of gas well deliverability is obtained by comparison of potential and apparent absolute open flow. Finally, field studies of Dina abnormal wells are performed to verify the accuracy of the method. Deliverability analysis show that the new approach has a great advantage in evaluating the production potential of wells with pressure fluctuation, and furtherly provides the criteria for wellbore management.
Application of Due Diligence Audit for Value Creation: Case Study from Gas PSC of Malaysia
Authors: Sinha Ankaj Kumar , Lim Hue Teng 
Published: October 2021

Abstract
As resource owner of all hydrocarbon assets of Malaysia, Petroliam Nasional Berhad (PETRONAS) through Malaysia Petroleum Management (MPM) is responsible for providing asset integrity assurance, maintaining producing assets in safe and operable conditions and ensuring compliance to data management by Petroleum Agreement Contractors (PACs). For mature fields nearing expiry of production sharing contracts (PSCs), it is even more critical to safeguard the integrity of petroleum facilities and to conduct an inventory check of acquired data during transition from existing to new PACs. A Due Diligence Audit (DDA) provides an important milestone to benchmark the health of existing assets (subsurface and surface) and outlining roadmap for future development opportunities for the PSC fields. This paper presents key technical results and value creation areas from the DDA conducted for one of the largest gas field PSC in Malaysia.
This gas PSC consisted of multiple gas fields and production hubs catering to a majority of gas production in the region. Although the fields had been in production for more than 20 years, maintaining production plateau rate and optimizing operating cost were identified as key concerns for long term sustainability. New development opportunities were also needed to mitigate the same. For existing fields, incremental recovery projects focused on lowering the abandonment pressure are planned. To maximize the utilization of gas processing capacity in production hubs, nearby gas fields have also been identified for cluster development and evacuation. Assurance on long-term gas supply is targeted through fast pace exploration in the early years of new PSCs to discover new gas development areas and to further increase the operating life of these hubs. As ageing assets, each of the fields also faced unique challenges such as liquid handling, subsidence issues and increasing inventory of idle wells. Through successful application of the DDA framework, a detailed technical assessment of deliverables was conducted along with liability management to address these asset integrity risks.
With the successful completion of DDA for these fields, the technical assessment deliverables have created significant PSC value by securing identified opportunities under minimum work commitments. In addition, it facilitated a roadmap for idle wells management plan and new technology in "Implement Replicate" phasing. This has helped PETRONAS to further monetize opportunities in ageing assets, and safeguard producing hubs for long-term gas supply.
This paper presents an efficient Due Diligence Audit workflow for long term value creation in mature fields and assets.
Application of Enhanced RPB Tool in Malaysian Oilfields for Gas Injection RF Benchmarking and Analogue Identification
Authors: Sinha Ankaj Kumar , Jalan Shlok , Ranjan Rakesh , Masoudi Rahim 
Published: October 2021

Abstract
Identification of an optimal field development plan is one of the most critical decisions for oil asset management. In the new norm of low oil prices, this assumes even more relevance for mature oilfields to maximize overall recovery. In greenfield developments and oilfields in early production life, the absence of a clear roadmap detailing their future development strategy can often lead to missed opportunities and sub-optimal recovery. To bridge this gap, Petroliam Nasional Berhad (PETRONAS) began identifying new improved oil recovery (IOR) opportunities in mature fields and started formulating an optimal development plan in greenfields. In 2019, PETRONAS embarked on implementing the Reservoir Performance Benchmarking (RPB) tool to evaluate reservoir recovery potential with waterflood. This paper will detail the Phase-II development of this data-analytics based tool which focuses on delivering a comprehensive roadmap, which includes other recovery mechanisms such as gas injection and reservoir under primary recovery.
Phase-I of RPB tool (SPE-196443) had considered water injection as a key secondary recovery process to evaluate the benchmark recovery factor for an oil reservoir. As part of Phase-II development, this has been further enhanced to evaluate field recovery potential and provide the benchmark recovery factor for primary recovery and gas injection processes. For fields under primary recovery, a comparative assessment between volumetric depletion and varying aquifer/gas-cap drive is conducted to ascertain the recovery potential. Assessment for incremental secondary recovery gains considers both gas injection and water injection scenarios in the enhanced benchmarking methodology. In addition, the benchmarking calibration methodology has also focused on incorporating additional reservoir parameters specific to each of the recovery processes for overall estimation of the benchmark value. The benchmarking tool also identifies analogue reservoirs to enable replication of best development practices and optimization of the development strategy.
With the deployment of this enhanced RPB tool, a comprehensive 5-year roadmap has been developed to improve Malaysian oilfields recovery. This has enabled PETRONAS to augment its resource funnel inventory, streamline its opportunity ranking and integrate project maturation tracking with existing digital platforms of its entire portfolio.
This is a novel benchmarking tool to assess reservoir potential recovery factor for primary and secondary recovery processes (both water and gas injection) along with analogue identification for replication of best development practices
Operational Data Repository as the First Step to Digital Oil Field
Authors: Alfajri Reza , Siregar Sakti Parsaulian , Sitanggang Liston , Hutasoit Andar Parulian 
Published: October 2021

Abstract
Digital oil field is a terminology that frequently appeared in the last few years. In the era of industry 4.0 and the proliferation of digital technology, oil and gas companies need to adapt in order to gain advantage in business process development, and this term is the answer. In digital oil field, data is significantly valuable. Therefore, robust database and real time data monitoring need to be developed.
Pertamina EP has established a robust, easy-to-access, and web-based database application called Operational Data Repository (ODR). This application handles end-to-end business process from exploration all the way to commercial. Several modules were integrated for this application and the main modules consist of exploration, exploitation, production, finance, safety and commercial. For every module in ODR, the first task to carry is to create and input master data. After database is created, calculation according to module's purpose is performed. Once the system is there, automatic data acquisition and monitoring will enter the picture.
Exploration module in ODR handles database of Pertamina EP exploration activities. This module include lithology, biostratigraphy, and geochemical data of exploration project in Pertamina EP. This module ensures that initial data of a structure is preserved and available. Exploitation module deals with oil and gas reserves and resources reporting process, well proposal for annual work plan, and surface project monitoring. This module rules development phase from subsurface to surface. Production module shows daily operational activities, production data, and quadrant mapping of wells productivity. Data from this module is taken for evaluating production and operation performance. Finance module handles company's financial report, including revenue, expense, and tax. Safety module handles work permit, hazard identification, risk assessment and control for every project and work plan. Safety is a very important aspect in a company and this module ensures that documents needed to perform work safely is well-documented and easy to submit and access. Last but not least is commercial module. This module consists of gas sales agreement documents (GSA), metering system location, and customer complaints monitoring. ODR has already been well-established, therefore Pertamina EP started its pilot project for automatic data acquisition for eight wells and currently on monitoring phase.
This paper describes Pertamina EP first step to digital oil field, which is developing virtual warehouse to store company's data. The step is strengthened with attempting for automatic data acquisition that will be integrated to the ODR for the next phase.
A Thorough Review of Machine Learning Applications in Oil and Gas Industry
Authors: Temizel Cenk , Canbaz Celal Hakan , Palabiyik Yildiray , Aydin Hakki , Tran Minh , Ozyurtkan Mustafa Hakan , Yurukcu Mesut , Johnson Paul 
Published: October 2021

Abstract
Reservoir engineering constitutes a major part of the studies regarding oil and gas exploration and production. Reservoir engineering has various duties, including conducting experiments, constructing appropriate models, characterization, and forecasting reservoir dynamics. However, traditional engineering approaches started to face challenges as the number of raw field data increases. It pushed the researchers to use more powerful tools for data classification, cleaning and preparing data to be used in models, which enhances a better data evaluation, thus making proper decisions. In addition, simultaneous simulations are sometimes performed, aiming to have optimization and sensitivity analysis during the history matching process. Multi-functional works are required to meet all these deficiencies. Upgrading conventional reservoir engineering approaches with CPUs, or more powerful computers are insufficient since it increases computational cost and is time-consuming. Machine learning techniques have been proposed as the best solution for strong learning capability and computational efficiency. Recently developed algorithms make it possible to handle a very large number of data with high accuracy. The most widely used machine learning approaches are: Artificial Neural Network (ANN), Support Vector Machines and Adaptive Neuro-Fuzzy Inference Systems. In this study, these approaches are introduced by providing their capability and limitations. After that, the study focuses on using machine learning techniques in unconventional reservoir engineering calculations: Reservoir characterization, PVT calculations and optimization of well completion.
These processes are repeated until all the values reach to the output layer. Normally, one hidden layer is good enough for most problems and additional hidden layers usually does not improve the model performance, instead, it may create the risk for converging to a local minimum and make the model more complex. The most typical neural network is the forward feed network, often used for data classification. MLP has a learning function that minimizes a global error function, the least square method. It uses back propagation algorithm to update the weights, searching for local minima by performing a gradient descent (Figure 1). The learning rate is usually selected as less than one.
Installation of Conductor Supported Platform CSP at X Field
Authors: Ngadiman Helmi 
Published: October 2021

Abstract
This technical paper presents the offshore installation execution work of Conductor Supported Platforms (CSP) at ‘X’ field. The knowledge sharing was based on the successful installation of three (3) numbers of CSP for ‘X’ development project. The platforms were installed at approximately of 70m water depth and encountered technical challenges during offshore execution.
‘X’ field is located about approximately 45km North West of Miri, Sarawak. The CSPs were installed by Derrick Barge (DB) via double blocks crane upending method for the substructures and conventional lifting method for the topsides. The CSP was designed for 70 meters water depth with four (4) numbers of vertical legs, four (4) numbers of skirt piles, and one (1) number of pin pile. The weight of the topside was about 600MT, meanwhile the substructure was about 1100MT respectively.
These CSPs marked as a pioneer in the installation of its kinds at 70m water depth in COMPANY. The concept required high accuracy of detailed offshore installation engineering. This configuration however had caused some challenges during installation. Among the major challenges were issues on the pin-pile verticality, substructure levelness and upending activities via double blocks crane upending method.
The effective strategies were adopted to improve the on-bottom stability by installing pin pile prior to substructure set down. The pin pile was installed by utilizing Subsea Fast Frame (SFF), in order to achieve pin pile's verticality. The crucial part during pin pile installation was to ensure meeting the verticality accuracy and minimum tolerance may high potentially impact the substructure install ability and meeting level requirement.
However, due to a big annulus gap at pin pile sleeve of the substructure had caused prolong in levelling operation. In order to improve subsequent platforms levelling operations, a set of centralizers were introduced and installed after confirming the pin pile verticality result, in order to reduce the annulus gap. Despite all the challenges aforementioned, the installation of CSPs were completed successfully and most importantly with Zero Lost Time Injury (LTI).
Blast from the Past, Solving Severe Congealed Oil Problems by Combining Existing Solutions
Authors: Hahijary Tirza , Kusuma Aditya Yudha , Jenie John Rizal 
Published: October 2021

Abstract
A mature field in central Sumatra, Indonesia, has been producing heavy oil for decades, and it has shown decreased production. The ESP, as the main lifting method, needs to be replaced more frequently due to mechanical damage by congealed oil. Many wells in that field were forced to be deactivated because of congealed oil plugging along the wellbore. The conventional method to tackle this issue is to pump hot water. This practice however did not give sustainable results after the treatment. The remedy of coiled tubing (CT) well cleanout with a wash nozzle has also not been considered successful because the congealed oil is too hard to penetrate. Furthermore, using mechanical devices such as CT milling tools has not been effective because the deposits stick to the mill. Considering the low-production-rate wells, high-rate fluid injection was proposed to meet cost criteria. Although the well was able to produce afterwards, production kept declining due to the production of congealed oil from the formation. A combination of high-pressure jetting tool and organic dissolver fluid was proposed as an alternative method to break the congealed oil. The method uses kinetic energy from the jetting tool to shatter the solidified oil by pumping brine. Afterwards, a fluid mixture composed of organic dissolver and additive is pumped to dissolve the remaining congealed oil.
Following the treatments, the pilot well showed significant improvements. The treatment successfully revived well production after the well had stopped producing for more than 3 months. The flowback tank was filled with as much as 10-in.-deep broken oil residue. Such a solid removal has not been accomplished with any other technique. The well has been producing for more than 10 months without any pump issues, and production continues to increase. Another three well candidates with low productivity issues were treated with the same technique. All the wells delivered good results. If, in the future, the congealed oil accumulates again, high-pressure jetting and organic dissolver will be the first method used for remediation. All the wells treated with this approach have been producing significantly more than those treated using any other technique, well beyond the target set by the operator.
This study discusses the benefits of combining the techniques of high-pressure jetting, organic dissolver, and high-rate injection to overcome severe congealed oil problems that impair well production. Details the approach are provided, and its effectiveness is compared to other former attempts to solve the congealed oil problem. This case also illustrates the importance of maintaining well interventions to improve production while meeting the cost criteria in this challenging time in the oil and gas industry.
An Industry First: Concept Selection, Material Testing, and Modelling Process for a Successful Managed Pressure Open Hole Gravel Pack Project
Authors: Lin Chih-Cheng , Tallin Andrew G. , Guan Xueyong , Kaura Jiten D. , Luces Sasha F. , Shayegi Sara , Oyler Kenneth W. , Reutzel Ronald A. , LaPointe Michael , Teoh Michael , Palisch Terry T. , Wong George K. 
Published: October 2021

Abstract
One of the major technical challenges to this project was placing horizontal open hole gravel packs (HzOHGP) within the narrow pore pressure to frac-gradient (PPFG) margin in the target reservoirs. This paper addresses the steps taken to overcome this challenge. To maximize the use of the narrow PPFG margin, the project combined a managed pressure drilling (MPD) system with low gravel placement pump rates made possible by an ultra-light-weight proppant (ULWP). Of the MPD systems available, the Controlled Mud Level (CML) system was selected over the Surface Back Pressure (SBP) system for several reasons. It enabled conventional gravel pack pumping operations and equipment and it accommodated the brine weight needed to inhibit the shales. A series of lab tests showed that the completion fluid density required to inhibit the reservoir shale reactivity was only possible using CML. An overall evaluation of CML showed that it was most suitable and offered the greatest flexibility for the gravel pack job design.
The special ceramic ULWP had to be qualified and tested. The qualification testing ranged from standard API and compatibility tests to full scale flow loop testing. The flow loop tests were needed to measure the ULWP transport velocity for the target wellbore geometry. Understanding the transport velocity is critical for gravel pack design and job execution planning. Once MPD and ceramic ULWP were selected, the gravel pack placement operations were simulated to demonstrate that their features increased the likelihood of successfully gravel packing in the target reservoirs. Small PPFG margins decrease the probability of success of placing a HzOHGP. In the target formations, the pressure margin is insufficient to safely execute HzOHGP conventionally; instead, the project combined MPD and the low pump rates facilitated by using ULWP to control circulating pressures to stay inside the narrow margin and place the gravel packs. The integration of CML and ULWP into in a gravel pack operation to control circulating pressures has never been done. The concept and its successful field implementation are industry firsts.