bluuebunny/crossref_metadata_2025_split huggingface dataset:
Data-Driven Production Forecasting for Shale Gas Wells Using Production Characteristics Analysis
Authors: Shin Hyo-Jin , Lim Jong-Se 
Published: October 2023

Abstract
Several studies have used machine learning-based techniques to improve the production behavior prediction in existing shale gas wells. However, few studies have investigated production prediction in new wells wherein no prior information is available. This is challenging because these predictions are generally based on the analysis of data available on existing wells. Therefore, in this study, data-driven analytics is utilized to analyze the production characteristics of existing wells and improve the predictive performance of the production for new wells.
Field data on the Marcellus Shale wells with production histories exceeding 48 months were collected from Enverus’ Drillinginfo. We derived production-related attributes of these wells and identified the key factors using principal component analysis to establish the production dependency on them. Subsequently, the prediction reliability was improved by classifying different production characteristics into groups, and using their trend lines to estimate the cumulative production of the existing wells. For new wells, we developed a model to classify groups based on key factors, and utilized probabilistic values from the classified groups to predict stochastic ranges of cumulative production using an artificial neural network.
The field data were normalized with respect to lateral length or the number of stages to enable comparison between multiple wells. Outliers of each input factor were excluded during pre-processing. An analysis of production characteristics was performed by classifying the existing wells into three groups. Results indicated that Group 2 was highly productive, with evident influence of normalized fluid volume during the middle and late phases of production. Further, initial variations in production tendency were observed in Groups 1 and 3 by spacing. Trend lines of classified groups were used to forecast the cumulative production per unit length (NP) of the existing wells. The observed error was less than 10 % in the prediction of NP 48 based on the analysis of NP 6 and NP 12. Additionally, high production variability in shale play is known to induce a rapid reduction in the production trend after the initial production. Therefore, a prediction model with NP of 6, 12, and 48 months was developed. To validate the model, probabilistic values of spacing and decline factors were used in the predictions of NP 6, 12, and 48, yielding an accuracy exceeding 80% and an error of approximately 10%.
The proposed multi-well productivity analysis is a trial-and-error process based on data-driven analytics, which can be used to predict shale production in any shale play. In addition, the range of the predicted probabilistic production includes the actual values; therefore, the prediction errors are small compared to those of previous methods for new wells. Consequently, time and resources expended for data acquisition are reduced, and the reliability of productivity forecasts in shale development is improved.
Fortifying Upstream Data Governance - Establishing Centralised Data Governance and Assurance Control Tower
Authors: Zait Nurshazareena Shuhada , Mohamed Ghazali Muhammad Azmir , Lee Hin Wong , Mat Ghani Normanisah , Nur Ismail Nur Aliah , Zakaria Zulhanizam , Mohamad Isa Mohamad Haneef , Azaman Dzulkarnain 
Published: October 2023

Abstract
PETRONAS Upstream is moving towards becoming a data driven organization. In order to ensure Upstream decision making is driven by trusted data, it is imperative to fortify Upstream data governance with structured and guided process and procedure, technique and methodology that define, build and operate data management knowledge areas as per DAMA DMBOK.
An innovative concept of establishing Data Control Tower as centralized data governance and assurance was designed and implemented to ensure that PETRONAS Upstream Data Governance is managed at the highest level with the following objectives:
Guardrail Upstream data standardization and consistency Oversight of data management activities Centralized data mastering Data quality performance monitoring Data catalog, business glossary and metadata management Data security control
Implementation of Recompletion Using Heavy Workover Unit 340 Klbs Unit to Solve Well Integrity Problem in New Oil Well: A Success Story and Lesson Learnt from Handil Field
Authors: Li Ulinnuha Iftitahul Lu'ayyi , Umar Arsalan , Suhartanto Andrian , Alyasa Muhamad , Maulana Muhammad Irfan , Wijaya Geraldie Lukman , Maz Nasuto Saidana , Setiawan Dedy , Wardhana Rahadyan Kusuma , Risal Miftachul , Jamal Muhammad Nadrul , Pradana Theodorus Aditya , Suwito Edy , Hidayat Mas'un , Setiadi Rahman 
Published: October 2023

Abstract
Well X is an oil well which was completed using the Mono Trip Gas Lift Completion (MTGL) in July 2019. Downhole safety valve (DHSV) problem observed since first well intervention performed on this well. From downhole camera running, it was observed DHSV's flapper was detached. To overcome this problem, a 2.3" Insert Pipe was installed transversely at the depth of the TRSV and ambient safety valve was utilized to replace the function of DHSV in order to allow the well to be produced. Due to the presence of 2.3" Insert Pipe and Ambient Valve, well intervention activities in this well were more difficult, longer duration due to more step, and had high potential for stuck. There are several unopened reservoirs in this well which still have a potential of around 235 kbbls of oil and 0.23 BCF of gas. After considering several options such as drilling a new well; perform recompletion with the rig; and rig less recompletion, this well was recompleted using HWU 340 Klbs unit. The job was carried out by cutting the tubing to a depth below side pocket mandrel depth, then installing a new upper completion with TRSV and some new side pocket mandrel additions. Tubing Swallowed Bell Guide Assembly is used as a connector between the existing completion and the new upper completion, then continued with the annulus cementing job. Through this innovation, the job can be completed within 17 days and total cost less than 700 kUSD, which resulted in savings up to 2 MMUSD when compared to drilling a new well, and succeeded in opening better access to the reservoir with a total value of up to 20.4 MMUSD.
Rapid Simulation and Optimization of Geological CO2 Sequestration Using Coarse Grid Network Model
Authors: Aslam Billal , Yan Bicheng , Tariq Zeeshan , Krogstad Stein , Lie Knut-Andreas 
Published: October 2023

Abstract
Large-scale CO2 injection for geo-sequestration in deep saline aquifers can significantly increase reservoir pressure, which, if not appropriately managed, can lead to potential environmental risk. Brine extraction from the aquifer has been proposed as a method to control the reservoir pressure and increase storage capacity. However, iterative optimization of the well controls for this scenario using high-resolution dynamic simulation models can be computationally expensive.
In this paper, we demonstrate the application of a so-called coarse–grid network model (CGNet) as a reduced-order model for efficient simulation and optimization of CO2 sequestration with brine extraction. As a proxy, CGNet is configured by aggressively coarsening the fine-scale grid and then tuning the parameters of the associated simulation graph (transmissibility, pore volumes, well indices, and relative permeability endpoints) by minimizing the mismatch of well-response data (rates, bottom-hole pressure) and saturation distribution from the fine-scale model. Calibration and optimization procedures are automated using gradient-based optimization methods that leverage automatic differentiation capabilities in the reservoir simulator in the same way backpropagation methods are used in training neural networks. Once calibrated, CGNet is employed for well-control optimization. Validation with the fine-scale model shows that CGNet closely matches the optimized net-present value (NPV). Numerical examples using the Johansen model, available as a public dataset, shows that the optimization can be accelerated up to seven times using CGNet compared with a fine-scale model. (Using a compiled language will likely result in significantly larger speedups as small models suffer from a disproportionately high computational overhead when executed in MATLAB.) This study implies that a reduced-order model such as CGNet can be a powerful data-driven tool for faster evaluation of CO2 geo-sequestration simulation, combined with proper reservoir monitoring program.
Alternative Solution for Deepwater Shallow Flow Hazard: Case Study from Shell Deepwater Project
Authors: Hoe Yijing , Heu Tieng Soon , Lee Shan Yik , Mohd-Radzi Razif , Yeap Fabian , Edwards Joseph , Charan Suri Chitra , Lo Rex 
Published: October 2023

Abstract
Gas bubbling was observed immediately post top-hole riserless cementation from the subsea conductor and wellhead in Field-A deepwater wells in Phase-1 and Phase-2 development campaigns. This has led to continuous underwater ROV monitoring and gas sampling requirement for structural integrity assessment. Foam cementing was considered but deemed impractical due to high logistical cost and limited regional experience. Conventional gas-tight cement with complex cement blend were attempted in another deepwater campaign with similar challenge but yielded inconclusive results.
Traditionally used to remedying lost circulation, thixotropic cement is a cement system where gel strength develops rapidly under static condition. In this case study, the thixotropic property was combined with shortened transition time properties to create a formulation that exhibits both aggressive gel strength development and a quick critical gel strength period post cement placement. However, pumping such cement system in big volume presented inherent risks where cement could prematurely gel up and harden in surface lines. This can potentially lead to CLIP, and in more severe cases, even total well loss. Comprehensive risk assessment including slurry design, sensitivity testing, quality control, and field trial were conducted prior to the execution. Saturated brine-based drilling fluid was utilized during drilling operations to enhance shale inhibition and prevent hole washout.
No bubbling was observed in all four wells in campaign after the cementation with thixotropic gas-tight system. Early planning and testing allowed for the successful implementation of this new cement system despite logistical challenges caused by the Covid-19 pandemic. Cement trial mix played a key role for the crew to understand the slurry behavior and access the equipment readiness. The outcome of this case study presents a promising solution for mitigating shallow flow hazard especially in Asia Pacific region where foam cement is not easily accessible.
Assessment of Field-Scale Geomechanical Risks Associated to Carbonate Reservoir Production in South Senoro Field
Authors: Younessi Ahmadreza , Sagita Romi , Mikhael Chrislianto Reynaldi , Laya Krishna Pratama , Helbet Ricky , Khawarizmy Atha 
Published: October 2023

Abstract
Senoro is a carbonate gas field in Banggai basin in Eastern Indonesian, an area with active collision margin. A comprehensive field-scale study is carried out to investigate the potential geomechanical related risks associated to the field production for the entire life of the Southern part of Senoro field. Well-centric geomechanical models were built for the exploration and appraisal wells in the South Senoro field. A robust field-scale geomechanical model is built for the area of interest which covers the entire South Senoro field. This is done by propagating the well-centric geomechanical model properties and parameters in the field-scale model using geostatistical approach tied with seismic attributed. Using a finite element approach, the model is then coupled with the reservoir flow dynamic model and simulated for the entire life of the field. The simulation results were used to assess the field-scale geomechanical related risks associated to production. The changes in stresses, strains and displacement induced by the carbonate reservoir depletion are obtained over the entire model at the end of each geomechanical simulation step. These are used to conduct detailed geomechanical analyses over the life of the field. The results shows that a stress path of approximately 0.69 is expected in the carbonate reservoir. This is while the stress changes in the caprock layer is relatively lower, and as expected, with a reverse trend. This is mainly because the reservoir compaction is relatively low with a maximum of 0.13% after 2,500 psi reservoir depletion. Subsequently, the maximum surface subsidence is also insignificant with less than 0.12 meters. Since the stresses within the caprock tend to slightly increase by production, the risk of tensile failure reduces over time. The risk of shear failure in the caprock appears to be negligible. The fault tau-ratio seems to increase only in the carbonate reservoir. However, it does not exceed more than 0.60 which indicates a stable state for the fault surfaces. Overall, the results show that there is no risk associated to compaction, surface subsidence, stability of the faults and caprock layer for the entire life of South Senoro field. The comprehensive workflow used to carry out the study covers all the geomechanical aspect of the risks associated to producing from South Senoro field which is essential to optimize the development plan and design of the surface and subsurface facilities.
Self-Degradable Loss Control Pill to Arrest Fluid Loss During Workover of Wells in Depleted and Naturally Fractured Reservoirs
Authors: Qamruzzaman Mohammed , Roy Dhirendra Chandra , Raman Ravi 
Published: October 2023

Abstract
Fluid loss during workover of subhydrostatic wells is a major concern while servicing the wells in brown/matured fields. Excessive fluid loss results in delayed well activation, formation damage and extra cost due to extra rig days. Loss control by placing a loss control material (LCM) pill has been a well-practiced method to control the fluid loss within desirable limits. However, presence of natural fractures or vugs in the reservoir prevents the formation of filter cake and significantly hampers the performance of these pills. Additionally, heavy use of conventional loss control pills results in formation damage which significantly compromises the productivity of well post workover and requires stimulation job for its restoration. This paper presents a novel self degradable loss control pill consisting of a multi modal distribution of polylactic acid (PLA) in powder, fiber and granular form that is highly effective for plugging/sealing the natural fractures and minimizing the fluid loss. With time and under the downhole conditions, the pill slowly undergoes self degradation and hydrolyze into completely water-soluble products thus minimizing the formation damage. The degradation behavior of the pill has been evaluated and filter cake buildup and aging studies have been performed through core flooding to optimize the particle size distribution of the PLA powder. The filter cake properties have been evaluated through HPHT filter press and results have been compared with the conventional pill. Flow back studies have been carried out to evaluate the cleaning efficiency of pill post activation. Finally, the proportion of PLA powder, fiber and granules has been optimized through fracture plugging studies as per API RP 13I. Application of PLA based LCM pill for loss control during workover is relatively newer concept with limited number of publications describing its intricacies including the loss control material, particle size distribution and pill design. This paper contributes by bridging the existing gaps and providing important guidelines for design and execution of self degradable loss control pill.
Increasing 11,000 BLPD on Bekapai Mature Field with Minimum Facility Modification Using the Inter-Platform Gas Lift Combined with Integrated Gas Lift Optimization (PROSPER & Macro-Excel)
Authors: Suseno Alfiza Danistya , Rusdi Runi Kusumaning , Guciano Muhammad Fauzan , Garmana Iqbal Aprian 
Published: October 2023

Abstract
Bekapai field has been producing for almost half a century, entering the depletion of reservoir pressure phase without adequate artificial lift facility. The biggest challenge faced by Bekapai as a mature field was aging facility in coupling with depleted reservoirs pressure. Other artificial lift methods such as ESP, PCP or other pumps are not suitable for this field due to limited space, no power source and sandy well characteristics. In-situ gas lift injection method is then applied to boost oil production. But not every active platform has high pressure wells that can be used as gas lift source. Ideally, a well intervention (WLI) job will be performed to provide a gas lift source for each active platform. Since no WLI barge dedicated to Bekapai, it can only rely to the available gas lift source instead of intervening new wells candidates.
At the beginning of 2023, a new ultra deep well (BX-2.G1) located at MWP-BX platform has been found and successfully Put On Production (POP) with production parameters: WHFP = 100 bar, WHFT = 72°C, Qg = 7.5 MMscfd, Qo = 25 BOPD, Qw = 232 BWPD. Rely on its high pressure, BX-2.G1 was utilized as a gas lift source well to inject weak wells only at MWP-BX. Unfortunately, there is no gas lift source on the neighbor MWP-BY platform, which prevents weak wells from producing at their best.
To address this common challenge, a suggested approach is the implementation of inter-platform gas lift. This technique involves utilizing a gas lift source situated on a single platform to infuse wells located across various platforms. This leverages the pre-existing pipeline infrastructure that interconnects these platforms. The facility integrity assessments and engineering modifications is needed for activating inter-platform gas lift in mature field with aging facility. Inter-platform gas lift utilizes 6 inch of BX - BY production trunkline to become a gas lift distribution pipe apart from a redundant 12 inch trunkline.
After all inter-platform gas lift requirements have been met, gas lift optimization is required to ensure optimal well injection performance. An integrated optimization of gas lift injection rate is performed on a monthly well test and updated using PROSPER and a visual basic tool (macro-excel). The well is then redesigned with gas lift valves, which is timed to coincide with the well intervention campaign. These innovations increased Bekapai's liquid production by more than 11,000 BLPD.
Inter-platform gas lift is the best way to enhance oil production in the Bekapai field by utilizing the existing aging facility and low cost installation. In the future, this method is expected to be applied in other company fields.
A Decade of Learning from Design and Operations of the First Subsea Automated Pig Launcher (SAPL)
Authors: Sulong Mohd Faizal , Nasri Huang Farah Julieana 
Published: October 2023

Abstract
This paper will outline the key features, design considerations and technology qualification program of the first Subsea Automated Pig Launcher (SAPL) installed and operated in a shallow water field development since a decade ago.
Field K is located in one of offshore Malaysian gas fields. The average water depth at the subsea location is around 80 meters. The field deliver non-associated gas since 2012 to a Central Processing Platform (CPP). SAPL was designed to accommodate the frequent pigging requirement for the purpose of efficient pipeline liquid management in the gas condensate system. The pigging operations are also critical to facilitate batch application of corrosion inhibitor to protect its 24-inch Carbon Steel pipeline. SAPL was selected as the preferred technology since it allows for single pipeline configuration from the subsea wells, as compared to dual loop pipeline that would impose additional CAPEX for the development. Pigging operation via downline from the vessel was eliminated due to less economically attractive proposal.
For the past 10 years, SAPL technology has proved to be one of the cost-effective solutions for subsea field developments that require frequent operational pigging. This paper will highlight the key learnings on application of SAPL technology for pipeline pigging operation. It will also provide some insights on the recommended engineering, construction, operation and intervention practices of the novel technology solution that could pave the way for reliable and cost attractive solutions for pigging operation in shallow water and deep water development in future.
Performance Assessment of Enhanced Geopolymer Cement Technology for CO2-Rich Well
Authors: Razak Ahmad Amirhilmi A , Sazali Yon Azwa , Zulkarnain Nurul Nazmin , Rahman Siti Humairah A , Amir Muhammad Syafeeq Ebining , Habarudin M Firdaus , Riyanto Latief , Hamid Afif Izwan A , Medvedev Anatoly , Yakovlev Andrey 
Published: October 2023

Abstract
The unique characteristics of Portland cement in terms of properties, availability and cost does not allow it to be replaced in many cases. However, there is a certainty about the properties of Portland cement in the long term because of thermodynamical instability of cement in the environment. These fundamental limitations of cement have prompted us to search for and study new materials with improved properties. According to a number of criteria, geopolymers were chosen as the most promising material. In this paper, the geopolymer formulations with 15 ppg density was prepared in the laboratory and the properties of the set geopolymers were investigated before and after exposure to an aggressive CO2 atmosphere. Results of 4-, 10- and 24-weeks exposure of geopolymers were compared with 15 ppg G cement and slag cement samples in the same conditions. Geopolymers demonstrated superior stability over G cement and slag cements at acidic conditions.