bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Dynamic Simulation Assessment for Relocating Flare System into Separated Platform Utilizing Idle Subsea Main Oil line
Authors: Winanto Winanto , Bahroinuddin Mukhtarus , Cahyono Endro , Thaliharjanti Margaretha 
Published: October 2021

Abstract
KLB is an offshore platform that consists of production wells and two train gas lift compressors. During well intervention, the KLB operation team must turn off the flaring system due to potential flare radiation of more than 500 BTU/hr-ft2at the working area and gas dispersion more than 50 %-LEL at the flare tip. The relocation of the KLB flaring system to the nearest platform keeps the KLB gas lift compressor operating during this activity. The relocation scenario can maintain the KLB platform production of 700 BOPD.
KLA Flowstation is the nearest platform to the KLB. It is separated one kilometer, connected by an idle subsea oil pipeline, but there are no pigging facilities due to limited space at the KLB platform. Therefore, the comprehensive assessment to relocate the KLB flaring system is a) Flare system study using Flare Network software to simulate backpressure and Mach Number at tailpipe in the KLA and KLB flaring system; b). Dynamic transient simulation using Flow Assurance Software to calculate backpressure, liquid hold up, and slugging condition in the flare KO drum; and c). Flare radiation and dispersion study.
The initial condition of the idle subsea oil pipeline was full of liquid as the preservation for a pipeline to prevent a further oil spill in case of a leak during the idle condition. The dewatering process for the idle subsea pipeline has been conducted by purging the pipeline utilizes 0.7 MMscfd gas lift with a pressure of 100 psig to displace liquid content to 20 bbl. The transient simulation for gas swapping was conducted at a gas rate of 4.1 MMscfd as the train compressor's flaring condition. The calculated backpressure at the KLB safety valve is 12.3 psig below the required maximum of 30 psig. The calculated liquid surge volume in the Flare KO drum during flaring is 17 bbl and can be handled by surge volume inside the KO drum. The predicted condensation inside the subsea pipeline shows that the maximum operation of the flaring system is limited to 30 days. The radiation and gas dispersion to the nearest facility is within a safe limit.
The KLB teams successfully conducted the relocation of the flaring system from the KLB platform to the KLA platform. The result was no interruption of production, no risk of radiation, and no potential explosion during a well intervention. Experience in the last two activities has confirmed that this method can prevent revenue loss of 19 billion rupiahs. This study has initiated a new engineering standard and best practice for flaring systems as opposed to the current practice which states that the flare location shall be at the same location as the production facilities with no pocket piping in between. This study and field experience have proved that the flaring system can be located on a different platform by conducting engineering assessments to ensure process and process safety criteria are within Company and International Standard.
Optimisation of Well and Layer Selection for Re-fracturing
Authors: Zhu Qi 
Published: October 2021

Abstract
In initial fracturing of tight oil and gas reservoirs, due to the influence of geological and technological factors, the fracture conductivity has decreased, and the single-well productivity has been reduced. It is urgent to repeat transformation to restore or increase productivity. Well selection and layer selection is one of the key factors that affect the design of re-fracturing and the effect of stimulation.
Based on a big database of well-sites, establishing machine intelligence theory determines the elasto-plasticity, permeability, porosity, completion parameters, production decline parameters and skin coefficient that affect the effect of re-fracturing stimulation by dimensionless parameter method of well and layer selection and its stimulation evaluation model.
Combined with artificial neural network and BP algorithm, the index weights of strata with different reservoir physical properties are calculated to analyze the final evaluation value of fracturing effect. On the basis of remaining oil distribution research, scale extended fracture repeated fracturing is increased, injection-production well pattern is improved, scale repeated fracturing effect is increased, well pattern is improved, target layer is repeatedly fractured, and oil increase effect is obvious after fracturing.
Embarking on a New Philosophy: Sand Control Design and Exclusion Method for a Field in Peninsular Malaysia, Best Practices and Lessons Learned for Future Development
Authors: M Zain Siti Nur Mahirah , M Zamani Nur Hidayah , Magna Bela Sunanda , AL Selladurai Jagaan , Hashim Saharul , Rosdi Mohd Hisyam , Ramirez Cristian , Tham Dennis 
Published: October 2021

Abstract
Field D is a massive oil-producing field, which consists of more than 15 blocks that have been developed since 1996. All types of completion methods, from openhole stand-alone screens and cased-hole circulating packs to frac packs, have been applied to help maximize field productivity while keeping sand issues to an acceptable level. However, some wells have begun to encounter sand issues, causing a drop in productivity and in some cases become shut-in because of sand accumulation in the tubing. Small fines (&lt;40 micron) are particularly prominent in the produced sand based on samples collected. A field development revisiting campaign was launched to target new drainage points and recover attic oil using existing slots to sidetrack to the targeted zone and install a new downhole sand control completion. The preferred treatment method is an extension pack (EP) after considering reservoir characteristics, namely close proximity to a coal layer, low permeability, and small fines production, among others. These challenges were addressed by combining the oriented perforation design and optimal sand control completion system using a single-trip multizone system, enhanced single-trip multizone system, and a stack pack with a properly designed proppant pumping strategy using xanthan carrier fluid, a fines-control acid system, and 20/40-mesh ceramic proppant with a 10-gauge wire-wrapped screen. Numerous sand control software simulations were performed to achieve tip screenout (TSO) and a sufficient pack factor while addressing all of the wellbore conditions. For the first time in this field, conductivity enhancer material was applied by dry coating it to proppant on-the-fly with the goal of controlling fines migration through the proppant pack, thus increasing porosity and leading to long-term conductivity. The process design, execution, minifrac analysis, and post-job matching for the frac pack treatment are discussed, which lead to the wells producing sand-free at higher than expected reserves and flow rates. Best practices and lessons learned from this campaign can be further used for new upcoming campaigns.
Pushing the Boundaries Through Successful Delivery of Highly Challenging ERD Well in Offshore East Java, Indonesia
Authors: Musa Mohd Zarir Bin , Tobing Jerry , Akbar Muhammad Ikhsan , Fajar Irshad , Nurrakhmadi Wienarno , Muttaqin Hamdan Yudanto 
Published: October 2021

Abstract
With the far-reaching reservoir target coupled with other surface constraint including fix well slot coordinate and pre-determined conductor size, the longest well with 2.5 ERD Index in Offshore East Java was pioneered. The team has big task in hand to ensure all aspect of ERD well engineering and construction are being addressed properly within the fast-paced time frame given. One of the approaches strategized by the team is to split the high angle big hole size long interval of middle section into two casing string which was not the common architecture applied in the other offset wells. The objective was to ensure that the middle section of the well will not be compromised and avoid complication in the deeper section of the well. Worth to mention that the middle section consists combination of challenging lithology that deserve the right solution to avoid unwanted problem. There are highly kartsitified carbonate formation, shale and sand interbedded formation, and thick time dependent shale formation.
To mitigate the challenges previously mentioned, intermediate section which is normally drilled and isolated with 17-1/2" hole × 13-3/8" casing in previous wells, now separated into two sections which require enlargement: 17-1/2" to 20" and 14-3/4" to 17-1/2". This paper focuses on 14-3/4" × 17-1/2" which is the most challenging underreaming operation in this well and the first of its kind in this field application.
Adding to the fact that the inclination reach 75 degree in this section, SOBM and RSS BHA are deployed to mitigate the torque and drag issue. State of the art modelling tool is also used by team to define effectively match BHA and drilling parameter with minimal lateral vibration and stick slip for this section Apart from drilling stage, the enlarged hole size requires a condition to have uncommon casing size and specification, 16" intermediate semi flush liner connection and 13-3/8" full flush intermediate casing connection to ensure sufficient annular area and less restriction during running to bottom.
The relentless effort to secure one the most critical ERD well construction phase has really paid off by allowing the next phase of operation to be executed as per plan thus assuring the overall well objective is met.
Analysis of South Australian Onshore Oil & Gas Well Decommissioning and Potential Impact on Regulatory Compliance, Environmental and Corporate Risk — Unified Risk Code
Authors: Kokkoni Panayiotis Peter , Salmachi Alizera 
Published: October 2021

The Cooper/Eromanga Basin is in central Australia and has been the focal point for oil and gas exploration and development in South Australia since the first commercial hydrocarbon discovery in 1963. In the years and decades following, thousands of subsequent wells have been drilled. The CE Basin spans across four states and territories covering an area ~35,000km2. The concentration of South Australian wells is situated in the Northeast of the state and sparsely concentrated in a 300km × 500km area (Figure 1) with the wells in this area being the focus of this research study.
Well decommissioning commonly referred to as Plug and Abandonment (P&A) aims to restore the natural integrity of geological formations that existed prior to drilling. It is a mandatory requirement for all wells and must account for the effects of any foreseeable chemical and geological processes from an eternal standpoint. The minimum requirement for abandonment of the South Australian wells is governed by Objective 6 Cooper Basin State Environmental Objectives (SEO): Drilling, Completions and Well Operations, November 2015 guidelines, which provides the compliance criteria for appropriate barrier installation and verification.
Well complexity is determined by the difficulty in achieving this minimum compliance requirement based on available data of well conditions, simplified in the form of a risk code.
Algorithm-Assisted Platform Location Optmisation Using Mixed-Integer Programming for Cluster Development Strategy in the Gulf of Thailand
Authors: Ekkawong Peerapong , Loboonlert Parichat , Seusutthiya Krongpol , Wongpattananukul Kongphop , Laoniyomthai Nuntanut , Thapchim Jiraphas , Nasomsong Rutchanok , Satsue Tepporn , Charucharana Thanawat , Lhosupasirirat Kasidis 
Published: October 2021

Abstract
The unique characteristic of gas fields in the Gulf of Thailand is the compartmentalized reservoir that requires a huge number of producing wells. The task of locating platform locations for whole field perspectives that also meet all operational criteria while minimizing the number of needed platforms is challenging. This decisional task has a critical impact on project viability, especially for marginal fields. This paper proposes an innovative solution to strengthen success in this business decision by integrating subsurface domain knowledge and optimization algorithms.
This study presents an optimization algorithm for determining the optimal locations of wellhead platforms with limited numbers to maximize hydrocarbon resources. Firstly, the algorithm performs verification matching between wellhead locations and subsurface targets throughout the field under drilling criteria. Next, the optimal platform locations are optimized using mixed-integer linear programming (MILP) with the primary objective of maximizing hydrocarbon resources. The algorithm literally runs with an increment in number of platforms until there is no incremental hydrocarbon resources gain and additionally summarizes the results as the number of platforms vs. coverage resources.
The algorithm has proven its viability by recommending more optimal platform locations in an actual field in the Gulf of Thailand. This algorithm-assisted workflow was able to reduce the number of required platforms. The main driver for this improved decision is that the MILP algorithm manage to improve well targeting and platform location selection under a large set of practical constraints. In contrast, manual workflow retains its limitations to consider them all.
This optimization also reduces the working time required for the whole process of well targeting and platform selection. Formerly, a typical workflow takes months of equivalent man-days. Conversely, this algorithm succeeded in completing the operation within just a few hours. Further, the subsurface team saved time by eliminating some repetitive tasks, i.e., they could focus on reviewing results extracted from the optimizer. Moreover, this work demonstrated the capability to extend and scaleup to other fields with similar concepts, which ultimately could lead to more benefits.
This innovative workflow translates the complicated subsurface procedure to a numerical optimization problem with a solid proven benefit from real field implementation. Apart from the positive business impact, this study shows that we can promote integration between modern data analytics and domain knowledge in oil and gas industry.
Unlocking Production Potential through Sand Management What–If Analysis in Digital Fields
Authors: Vo Nghia Tri , Hermann Roland , Fuenmayor Roberto 
Published: October 2021

Abstract
Sand production associated with oil and gas producers is one of the oldest problems in the industry and is typically in unconsolidated sandstone formations. The stresses caused by the fluids flowing into the wellbore are often sufficient to produce fine sand particles.
Sand production may cause operational problems such as disposal of produced sand, sand erosion of downhole and surface equipment, and loss of primary containment (LOPC), which is the most important reason for controlling sand production.
In actual field operation, a sand management program is usually implemented to manage sand challenges which limits to monitoring and basic analysis. The proposed sand management solution in this paper performs sensitivity analysis (known as what–if scenarios) using model–based sand erosion calculation to analyze different possible operating scenarios with the objective of preventing and minimizing sand issues.
The solution also helps to minimize risks related to well, facilities and avoiding cost or production losses due to sand production. It recommends the operational settings to achieve maximum production rates while ensuring operating within safe erosion limits and without sand deposition risk.
A Wellbore Pressure Calculation Method Considering Gas Suspension in Wellbore Shut-In Condition
Authors: Zhang Zhi , Sun Baojiang , Wang Zhiyuan , Pan Shaowei , Lou Wenqiang , Tong Shikun , Guo Bing 
Published: October 2021

Abstract
In the oil industry, the drilling fluid is yield stress fluid. The gas invading the wellbore during the drilling process is distributed in the wellbore in the form of bubbles. When the buoyancy of the bubble is less than the resistance of the yield stress, the bubble will be suspended in the drilling fluid, which will lead to wellbore pressure inaccurately predicting and overflow. In this paper, the prediction model of gas limit suspension concentration under different yield stresses of drilling fluids is obtained by experiments, and the calculation method of wellbore pressure considering the influence of gas suspension under shut-in conditions is established. Based on the calculation of the basic data of a case well, the distribution of gas in different yield stress drilling fluids and the influence of gas suspension on the wellbore pressure are analyzed. The results show that with the increase of yield stress, the volume of suspended single bubbles increases, the gas suspension concentration increases, and the height at which the gas can rise is reduced. When the yield stress of drilling fluid is 2 Pa, the increment of wellhead pressure decreases by 37.1% compared with that without considering gas suspension, and when the yield stress of drilling fluid is 10Pa, the increment of wellhead pressure can decrease by 78.6%, which shows that when the yield stress of drilling fluid is different, the final stable wellhead pressure is quite different. This is of great significance for the optimization design of field overflow and kill parameters, and for the accurate calculation of wellbore pressure by considering the suspension effect of drilling fluid on the invasion gas through the shut in wellhead pressure.
A Comprehensive Review of the Fourth Industrial Revolution IR 4.0 in Oil and Gas Industry
Authors: Temizel Cenk , Canbaz Celal Hakan , Aydin Hakki , Hosgor Bahar F. , Kayhan Deniz Yagmur , Moreno Raul 
Published: October 2021

Abstract
Digital transformation is one of the most discussed themes across the globe. The disruptive potential arising from the joint deployment of IoT, robotics, AI and other advanced technologies is projected to be over $300 trillion over the next decade. With the advances and implementation of these technologies, they have become more widely-used in all aspects of oil and gas industry in several processes. Yet, as it is a relatively new area in petroleum industry with promising features, the industry overall is still trying to adapt to IR 4.0. This paper examines the value that Industry 4.0 brings to the oil and gas upstream industry. It delineates key Industry 4.0 solutions and analyzes their impact within this segment. A comprehensive literature review has been carried out to investigate the IR 4.0 concept's development from the beginning, the technologies it utilizes, types of technologies transferred from other industries with a longer history of use, robustness and applicability of these methods in oil and gas industry under current conditions and the incremental benefits they provide depending on the type of the field are addressed. Real field applications are illustrated with applications indifferent parts of the world with challenges, advantages and drawbacks discussed and summarized that lead to conclusions on the criteria of application of machine learning technologies.
Reservoir Souring Prediction in Deepwater Reservoirs for Field Development Planning
Authors: Hanifah Mohd Azri , Panuganti Sai Ravindra , Zakaria Nur Atiqah , Kamarul Zaman Nur Hazrina , Tewari Raj Deo 
Published: October 2021

Abstract
A deep-water Field X with two major Reservoirs U and L discovered recently offshore Malaysia is on development for early production. The subsurface plan for the Field X includes water injection. But the presence of sulphate rich seawater can provide a favorable environment for souring activity to take place. This study evaluates the reservoir souring potential for the green Field X as a result of seawater flooding.
Reservoir souring is the increase of the hydrogen sulfide (H2S) concentration in produced reservoir fluids. As hydrogen sulfide is a highly toxic and corrosive gas, the production of H2S has a huge impact on the safety, infrastructure and facilities of the field. Whether a reservoir is susceptible to souring is dependent on a variety of factors. Some of these include water injection flow rate, temperature of the reservoir, presence of bacterial nutrients and rock minerology.
Effective prediction of biogenic reservoir souring using computer models is essential when undertaking major technical and economic decisions regarding field development. For H2S concentration calculation PETRONAS utilized in-house stand-alone modeling tool that considers physicochemical hydrodynamics of multiphase flow, heat transfer, substrate propagation and bacterial activity. The simulator looks at bacterial growth both in planktonic and sessile forms. Monod kinetics is applied for the growth of bacteria, leading to the consumption of sulphate and volatile fatty acids which in-turn is linked to H2S generation. Along with H2S propagation, H2S scavenging by rock and H2S partitioning between the various phases is also accounted for. The model can also deal with the effects of lift gas, reinjection of sour produced water, injection of biocide and nitrite. Since the Field X is a green field and historical production data is unavailable, the model is calibrated against the provided field development plan (FDP) data with sensitivity analysis.
The simulation runs show that the H2S breakthrough occurs before the end of production. The amount of H2S produced indicates that the risk of reservoir souring associated with seawater injection in U and L Reservoirs of the Field X is high. It is recommended to evaluate different reservoir souring preventive measures in combination with mitigative options in terms of chance of success, risks, and cost (CAPEX/OPEX) in the context of the Field X development plan.