bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technical Economical and Risk Analysis Methodology for Defining the Optimum Positioning of the Electrical Submersible Pump System for Production of Heavy Oil in Deep Water
Authors: Cavalcante Barbara Ferreira , Baioco Juliana Souza , Jacob Breno Pinheiro , Urupukina Nicolas Paes 
Published: October 2019

Abstract
In an oil field development, the choice of the appropriate artificial lift method is extremely important to obtain the best financial return for the project. The most efficient artificial lift method for heavy oil is the ESP, in the perspective of lift capacity and flow assurance, but, due to its low MTTF (Mean Time to Failure), in some cases, the associated cost for the offshore workovers is prohibitive. An alternative to reduce the cost of the workover is positioning the ESP in the seabed, in a pumping skid (Subsea ESP / skid-ESP). Positioning the ESP in the seabed, however, reduces the initial well flow rate. Most commonly, the Artificial Lift Method is chosen based on the previews experience of the operator, not giving appropriate effort to a technical and commercial evaluation. This paper proposes a methodology to provide quantitative data to assist the decision of the best positioning of the pumping system, inside the well or on the seabed, in order to obtain the best financial return.
The methodology is based on three stages: technical evaluation, which is an eliminatory step, based on the GVF (Gas Volume Fraction) limit that the pump can handle without flowing problems; then, an economical and risk analysis are performed for both projects (ESP and skid-ESP). Three case studies were performed to evaluate the proposed methodology, and to confirm that it is a good tool to assist the decision of the best positioning of the pumping system.
The results show that the three stages proposed are important. One of the three cases show a scenario where the skid-ESP is declassified in the first step of the methodology because of the high GVF calculated for the project, above the limit for this specific well. In the other two cases all the three stages of the methodology were applied. The economical deterministic analysis was not enough to define the best positioning of the pumping system, in order to obtain the highest financial return, and the probabilistic risk analysis was essential to obtain quantitative data to support an efficient decision. In both cases the suggested positioning of the pumping system was the seabed (skid-ESP or subsea ESP).
In the literature, some works propose methodologies to choose the appropriate artificial lift method. Some of them offer an economical evaluation tool; but a methodology that includes the subsea ESP as an option for heavy oil deep water projects was not found in the literature. This paper proposes a methodology that can be easily applied with the software's commonly used in the industry, therefore adding information to the existing body of literature that can benefit practicing engineers.
Collaborative Bit and Reamer Design Solution for Performance Drilling in Salt and High Durability in Challenging Subsalt Interval in One Run, Deepwater Gulf of Mexico
Authors: Havard Katherine , Durairajan Bala , Stith Steven , Goyal Sanjay , Trunk Philip , Nagaraj Mahavir , Trahan Dexter , Descamps Guillaume , Dykstra Mark , Louback Leonardo , Norvell Marcus , Pinard Christopher , Zhang Youdan , Rabei Rob , Halpin Matthew 
Published: October 2019

Abstract
This case study highlights the challenge of identifying the root cause of bit failures and provides an iterative design solution for maximizing drilling performance on a deepwater Gulf of Mexico (GoM) field development project. The well design and project economics required drilling through two distinct lithologies: salt followed by subsalt sediments consisting of plastic shale, abrasive sands, and marl. The operator wanted to drill through these in the same interval, in one run, while simultaneously achieving high rates of penetration (ROP) and maintaining durability for the entire interval.
Offset wells from previous operations in the area provided an initial starting point for the design, despite being quite different from the new well plan. A new drill bit and reamer combination were developed and built for the first well. In addition, the bottomhole assembly (BHA) design was optimized and detailed drilling parameter roadmaps were provided for the field crew. When the first run resulted in a premature bit failure, an in-depth post-run analysis was completed. A rapid response root-cause analysis was conducted, which resulted in a new bit design and expedited manufacturing to deliver the new bit within the tight timeline between consecutive wells.
Historical data from the Exploration &Appraisal (E&A) wells in the field indicated coring as the prevalent form of bit failure in the subsalt interval and loosely correlated with drilling of a middle Miocene sandstone. However, the wide range of bit vendors, bit sizes, and dull conditions in the data created uncertainty on root cause of failure. Although a good ROP was achieved in the salt section on the first field development well, the bit suffered premature wear in the subsalt interval, resulting in two additional trips to drill the interval. Each worn bit was thoroughly analyzed in conjunction with the drilling parameters and mud logging data from each bit run. Against the previous assumption of coring being a result of drilling abrasive sandstones, it was now determined that the failure mechanism was most likely a result of drilling shales with high bottomhole pressure causing plastic behavior, regrinding of cuttings at the bit face, and insufficient cuttings evacuation. An entirely new bit design was generated to prevent this failure mode and manufactured in time for the next well. The new bit design combined with revised drilling parameters strategy resulted in the most successful run ever in the field: 10,854 ft drilled (7,000 ft of reaming) in one run at high ROP in the salt followed by good ROP and excellent durability in subsalt formations.
Visualization of Ensembles of Oil Reservoir Models Based on Pixelization, Small Multiples and Reservoir Similarities
Authors: Silva Celmar Guimarães da , Santos Antonio Alberto Souza , Schiozer Denis José 
Published: October 2019

AbstractProviding an overview of an ensemble of oil reservoir models could help users compare and analyze their characteristics. Approaches that show a single model at a time may hamper analysts’ understanding of the whole model set. In this paper, we propose two visualization approaches that show multiple reservoir models, simultaneously and on a single screen, with the goal of helping users to compare models and improve their understanding of ensemble characteristics. First, we calculate 2D models from the ensemble's 3D models. We then create two visualizations that represent ensembles of these 2D models. The Small Multiples approach lays out heatmaps of 2D models side-by-side on a grid. Pixelization approach shows n 2D models in a single heatmap, where each cell (i, j) contains n subcells that represent values in the coordinate (i, j) of each model. Both approaches display their elements (heatmaps and subcells) clustered by X-means, which may help analysts identify similarities and representative models in the ensemble. We used two types of distance matrices: based on Euclidean distance of models for a given property or, based on Euclidean distance of feature vectors of the 2D models. We tested our approaches within models based on Brazilian benchmark cases corresponding to a turbiditic reservoir (UNISIM-I-D/M/H) and a presalt carbonatic reservoir (UNISIM-II-D). As a result, the Small Multiples approach presented clusters of similar models for some properties of the ensembles we studied, e.g. eight clusters of porosity values in UNISIM-II-D's ensemble. This fact suggests that eight representative models can represent the ensemble, regarding porosity. Also, a Pixelization approach revealed patterns that happen in specific regions of all models of an ensemble, such as an abrupt change of porosity values in the northwest region of UNISIM-I-M's models. Both approaches have the potential to help analysts perceive situations that would be improbable to observe in a graph with only mean values for each cell. Therefore, our proposal can be helpful to users who need to deal with uncertainties and have an overview of ensembles of models for better understanding and decisionmaking, e.g. when they need to choose representative models for a process of decision analysis related to petroleum field development and management.
1st Development of Advanced Purification of Produced Water Technology at Greater Sirikit Oil Field by Dissolved Gas Flotation Technique
Authors: Lertrojanachusit Nattapong , Thunmasarnrit Urisa , Techasuwanna Ratipat , Linjongsubongkoch Phansak , Sa-Nguanwong Ittiwat , Kiravanich Parntip , Metheethara Pongsak , Umpuch Saran 
Published: October 2019

Abstract
The production of S1 Greater Sirikit Oil Field production primarily contributes from waterflooding operation, where water is reinjected into reservoir to increase reservoir pressure and sweep movable oil to adjacent production wells. Estimated oil gain from waterflooding is expected to be 34 MMSTB with upside volume of 19 MMSTB. One of the complexities of waterflood operation is water qualities. As High solid particles and oil content presenting in injected water leads to reservoir plugging indicating by an increase in injection pressure and reduction in injection rate. With 53% of total water injection wells show signs of plugging, water quality improvement is one of the major projects initiated by S1 asset to tackle the problem.
Inadequate produced water treatment results in excessive solid particle and oil in water content. Eventually, it will effect on waterflooding and EOR performance. To maintain production, it is required to improve quality of water treatment in order to sustain oil gain. The gas flotation is one of promising technology and practically established methods to enhance separation of oil substances and particulates from water when simple gravity separation is not sufficient to reach the desired concentration.
In this project, the most challenged of this project are of necessity of Outlet TSS Concentration below &lt; 20 and 80% removal particle size &gt; 5 microns and Oil Outlet concentration below 25 ppm, whilst the TSS and oil inlet are approximate 200 ppm. The conventional flotation technologies consists with two main systems as detailed below. (1) Induced Gas Flotation Technology (IGF), (2) Dissolved Gas Flotation Technology (DGF). The difference between DGF and IGF is the bubbles size generation. Typically, the IGF unit produces bubble sizes ranges more than 100 microns, whilst the DGF unit creates bubble sizes below 100 micron.
Engineering team sought for appropriate technologies by reviewing COMPANY's past projects as well as screening the commercial channels. Apart from that, team amalgamated with Chulalongkorn University to gain academic point of view and perform JAR test to confidentially ensure Licensor's Technologies. Several factors shall be controlled and optimized to accomplish the performance guarantee via consideration of Flotation technique (DGF and IGF), Retention Time, Bubble Size, Coagulant & Flocculants Chemical properties, Chemical Compatibilities, Operating Condition Control (Pressure, pH).
In addition, the selected vendor executes engineering design and construction to deliver superior water quailities. Starting DGF unit to conduct performance test run, DGF unit captivately devises positive outcome of water treatment and demonstates high accuracy and reliable with corresponded correlation model when feed condition changes.
FPSO Hull Brackets Repair by Cold Bonded Reinforcements - Project Lessons Learnt from a World First Offshore West Africa
Authors: Paillusseau Christophe , Errotabehere Xabier , Florio Vito , Bulboaca Marcel , Pinto Guilherme , Galter Andrea 
Published: October 2019

Abstract
An increasing number of Brazilian floating platform units are currently entering a mature age inducing numerous asset integrity issues. As corrosion damages FPSOs’ hull structures, costly structural maintenance operations in extreme marine conditions are sometimes necessary. Crop and renew are very labor-intensive operations and usually require dry docking vessels. The nature of an FPSO operation practically demands it stays offshore, which raises several operational, safety and financial challenges. Indeed, dealing with flammable substances means that the use of conventional hot works techniques, such as welding or grinding, involves many critical safety assessments and/or production shutdowns. Thus, the challenge would be to carry out these repairs offshore while guaranteeing high safety standards and avoiding production shutdowns. FPSO operators, like SBM Offshore, have therefore been looking for a while for "cold work" in-situ solutions that guarantee safe and economical hull repair.
This paper will describe how SBM Offshore streamlined a world first implementation of a disruptive innovation (from TRL 5 to TRL 7 as per API) within less than a year through a partnership with COLD PAD, an industrial start-up of only 3 people at the time it was first proposed. It covers risk assessments, expert analysis, and overall qualification process.
It will also detail how Classification society was involved as well as typical lessons learnt from the project execution with a focus on the offshore campaign which took less than two weeks. Finally, the paper will provide indications on the advantages such a solution generates for FPSO hull asset integrity in terms of safety, planning, economics (reduced total cost of ownership) and how it can be extrapolated to lower OPEX for deepwater ageing FPSOs.
The business case considers an FPSO located in deepwater West Africa where, in 2016, SBM Offshore identified a set of corroded brackets in a void tank located close to two crude oil tanks. Classification Society imposed steel renewal for 4 of these brackets. After engineering assessment, it was concluded that conventional hot works would yield to a highly detrimental production disruption. At the same time, COLD PAD was finalizing the co-development with TOTAL and IFP Energies Nouvelles of an innovative alternative to "crop and renew" for structural reinforcement. ColdShield™ is specifically dedicated for the on-site maintenance of FPSO hulls without the need for hot works, thus avoiding production disruption for several scenarios. This original repair technique obtained a class approval with an anticipated service life of more than 10 years based on an established methodology of bonded composite reinforcement, used in other industries such as aerospace.
Improving Recovery Factor in Campos Basin
Authors: Ferreira da Silva Patricia , Moreira Branco Celso Cesar , Bampi Dirceu , Echenique Silveira Gustavo , Pereira Nunes Fabiano , Faerstein Marcos , Garcia Cordeiro Tessarolli Fernanda 
Published: October 2019

Abstract
This paper describes recent efforts into continually increasing the recovery factors in the Campos Basin reservoirs, which translate in significant investments foreseen for the next years to increase the production and recovery of the Basin. Some strategic efforts comprise measurement and critical analysis of current recovery factor, evaluation of recovery potential per reservoir and the creation of initiatives focused on the main technical requisites that would allow higher recoveries.
Campos Basin complexity, along with the maturity of the existing infrastructure, brings new challenges to the continuity of production. Among those challenges are the capacity to process large amounts of produced water and the demand for revitalization of production facilities, including topside, subsea and new wells.
Despite excellent results achieved in pre-salt reservoirs in Santos Basin in the recent years, Campos Basin remains an important province for Brazil's oil production. Still responding for 40% of the current production of oil in Brazil, the basin presents a promising future in the next decades. Revitalization projects, development of recent pre-salt discoveries and concession contract extensions are among the ongoing efforts towards Campos Basin renewal.
Along with operations and complementary projects, a strategic program called RF Ambition was set up in 2019, aiming to: deepen the diagnosis of the recovery factor per reservoir;establish recovery targets and ambitions for each reservoir;identify initiatives to boost recovery;provide the technical support to deploy the projects with potential to allow achieving the targets and ambitions in Brazilian fields.
An accurate diagnosis of the basin's recovery factor relies on a careful and thorough detailing of its reservoirs. Campos Basin has hundreds of production zones with different lithologies, in place volumes, types of fluids, geological complexities and water depth. Data analysis, evaluation and comparison to analytical estimates and international benchmarks can minimize the risk of reaching superficial or even incorrect conclusions.
The remaining potential of the reservoirs, approached by the identification of opportunities, translates into mid- and long-term supplementary projects to exploit undeveloped zones and optimize the recovery of the reservoirs, thus increasing overall recovery of the fields in Campos Basin. The aggregated contribution of these new opportunities integrates an ambitious target of recovery factor for the basin.
There are significant opportunities to increase Campos Basin's recovery factor and, to achieve the forecasted targets, technical and economic challenges must be overcome with the contributions of all agents involved in the upstream chain.
Reduction of CAPEX & Optimization of OPEX with Innovative Ideas by Integration with Brown Field and Green Field Development to Achieve Zero Venting
Authors: Sunnapu Ravi Kanth , Awang Ahmad Anas 
Published: October 2019

Abstract
Baronia field is located in Sarawak Operations, Miri and started production in the year 1973. It consists of two process complexes BN–A and BN–B. Each of these complexes has its own satellite vent platform which are BNV-A and BNV-B.
In line with PETRONAS statement of purpose ‘A Progressive Energy and Solutions Partner Enriching Lives for a Sustainable Future’, the operators had initiated to adapt sustainability as a key element in PETRONAS operations. Aligned with BDO EOR PSC venting/flaring reduction roadmap, in 2010, SKO Reliability and Integrity Team were driving two vent to flare conversion project (BNV-A and BNV-B) to be incorporated. The BNV-A vent to flare conversion project was completed at a cost of USD 9.6 million. The high cost has raised concerns to the BNV-B vent to flare conversion project as it was considered a major investment with no expected economic revenue returns.
A new project, BARDEGG-2/BN EOR, came up to develop a new Central Processing Platform (BNCPP-B) bridge linked to existing facilities (BNG-B), for processing of new Non Associated Gas (NAG) fields & EOR. BNCPP-B is designed with its own flaring system for the new facilities. The green field project team prefer not to touch any existing brown field scope to avoid complications.
In view of this matter, SKO Operations Readiness & Strategic Assurance team (ORSA) has been able to come up with a brilliant idea of achieving zero continuous venting and cost optimization. The proposed innovative design is exclusively from SKO ORSA team and was supported by SKO Management.
In this paper we will demonstrate the innovative approached by operators in order to achieve zero continuous flaring/venting in Baronia offshore field. The results and observations post the realization of design will also be discussed. The impact has been huge in terms of enhanced production continuity and plant reliability, maximized environmental sustainability by reduction of greenhouse gas emissions, and major cost savings.
On the Shared-Actuation Control for the Operation of Manifolds in Subsea Production Systems
Authors: Rabello Alexandre , Neto Dorival Natal , Coelho Eduardo José de Jesus , Seraco Estevan Pereira , Destro Wagner 
Published: October 2019

Abstract
This article presents a set of analysis and results on Shared-Actuation Control (SAC) techniques, intended for the remote control of valves in subsea manifolds. The discussion covers historical aspects, including presentation of real cases of SAC in Brazilian fields of Petrobras, as well as covers a conceptualization for the technique. The formulated concepts are used indeed to derive a methodology, intended to guide the development of SAC schemes, during engineering projects of subsea manifolds.
The discussion is based in part on the unique experience accumulated by Petrobras in the last 20 years, with the development and introduction of a SAC-based subsea manifold in Campos Basin, Brazil, and the latest development efforts ongoing by 2019 for a new generation of SAC, for the application in subsea manifolds to be installed in ultra-deep waters of Pre-Salt fields, in Santos Basin, Brazil.
The methodology proposed in this article is based on a comparative approach which aims to incorporate, on design of SAC, the best engineering practices and lessons learned from traditional Electric-Hydraulic Multiplexed Control Systems (EHMCSs). We refer to such approach as the Inheritance & Counterbalance (I&C) Methodology, since it is based on the application of two specific principles, namely, the Inheritance and Counterbalance Principles. The principles are proposed in this article as well. Taking as starting point a set of technical characteristics of EHMCSs, such as employment of redundant subsea electronics and methods of subsea installation, a subsea engineer can apply the I&C Principles to determine if SAC should inherit a given EHMCS characteristic or, if inheritance is not feasible for some reason, adopt alternative requisites on SAC, in order to counterbalance the effects of such no inheritance.
The conceptualization of the I&C Methodology allow us effectively applying it, to obtain as result a table of engineering requisites, suitable for SAC schemes destined to subsea manifolds. The proposed table is presented in this article and incorporates several engineering aspects, which are arbitrated from the knowledge on previous applications of Petrobras in subsea control systems. Such applications include both SAC schemes and EHMCSs, featured on fields of Campos and Santos Basins.