Singapore Section

Production Optimisation of Conventional and Unconventional Wells with ESP Real Time Data - Sponsored

Sponsored Kindly by Artifical Lift Solutions Pty Ltd  Abstract: Optimising production has always been important, but there is naturally a greater focus on high rate wells, such as those produced with ESPs (Electrical Submersible Pumps). A key driver is arresting decline while minimising infill drilling, which is often achieved by identifying wells with skin to identify stimulation candidates and increasing drawdown on wells with good pressure support. With unconventionals, accelerating production while minimising power consumption become dominant goals. This presentation explains how real-time gauge data enables high-frequency, high-resolution downhole flow rate measurements on ESP wells. Thereby providing both rate and pressure, which are essential to enabling inflow characterisation and thereby identifying optimisation opportunities without the need for traditional buildups, which cause production deferment.   Fortunately, technology advances have improved real time data quality in terms of both sampling frequency and metrology.  There has also been a reduction in the cost of measurement, transmission and storage, which signals the true dawn of the digital age. The presentation therefore also reviews how real time data enables increases in well uptime and ESP run life as well as minimising power consumption.  Using material from recent SPE papers, both theoretical methodology and real case studies are presented to illustrate the value of real time data for both conventional vertical wells and unconventional multifracked horizontal wells.  While the case studies are based on ESP applications, the lessons learnt on how to extract value from real-time data can be applied to other artificial lift techniques, especially since inflow characterisation is generic.   Biography: Lawrence Camirelli has over 33 years of experience in production operations of which 27 years have been focused on artificial lift in a variety of roles ranging from field and application engineer to his current role as Global Domain Head, which is Schlumberger’s most senior technical position in the Artificial Lift Division.  He has published over 16 SPE conference papers and 3 patents covering all aspects of ESP operation such as inflow characterization and advanced completions.  This body of work is particularly noteworthy as it combines theoretical explanations and field case studies using real time data. Kindly supported by Artifical Lift Solutions Pty Ltd

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DATE CHANGE - Compositional Simulation that is Truly Compositional

Abstract:    Current compositional simulators include compositional equation-of-state fluid models, but do not account for compositional effects on relative permeability, capillary pressure, and grid-block flux calculations.  Relative permeability, for example, is still based on “old thinking” related to labeling of phases as “oil, gas, and water.”  Labeling causes significant discontinuities that can result in inaccuracies and instability in simulations of compositional processes, such as those for enhanced oil recovery (EOR).    This presentation will show you why labeling is “old thinking” and how labeling generates discontinuities and simulation errors in compositional processes.  Several example cases, including water-alternating-gas and surfactant flooding, are given using a new type of compositional simulator with all labels removed.   One component of the novel simulator is the development of an equation of state (EoS) for relative permeabilities that eliminates phase labeling.  The relative permeability model is physically based and captures complex hysteresis effects through saturation and phase connectivity as well as changing wettability, interfacial tension, and pore morphology.   Results show increased robustness, improved accuracy, faster computational times, and less instabilities when phase labeling is removed.   Biography:   Russell T. Johns is the George E. Trimble Chair of Energy and Mineral Sciences at the Department of Energy and Mineral Engineering at The Pennsylvania State University. He also holds the Energi Simulation Chair in Fluid Behavior and Rock Interactions.  He recently served as Chair of the Petroleum and Natural Gas Engineering Program, and is currently the Editor-In-Chief for SPE journals.    Prior to his current position at Penn State, he served on the petroleum engineering faculty at The University of Texas at Austin for fifteen years.  He also has nine years of industrial experience as a petrophysical engineer with Shell Oil and as a consulting engineer for Colenco Power Consulting in Baden, Switzerland.  He holds a BS degree in electrical engineering from Northwestern University and MS and PhD degrees in petroleum engineering from Stanford University.  He has over 250 publications in enhanced oil recovery, thermodynamics and phase behavior, unconventional gas engineering, multiphase flow in porous media, and well testing.  Dr. Johns received the SPE Ferguson medal in 1993, the SPE Distinguished Member award in 2009, the SPE Faculty Pipeline award in 2013, the 2016 SPE international award in Reservoir Description and Dynamics, and the 2018 Wilson Excellence in Research award from the College of Earth and Mineral Sciences.  He is currently director of the Enhanced Oil Recovery consortium in the EMS Energy Institute at Penn State University.

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President's Visit: Shauna Noonan

The SPE Singapore Section will have the honor of receiving the visit of Shauna Noonan, the SPE 2020 President.

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Porosity Determination from Mechanical Measurements in Carbonates

Abstract: The advent of pressurised mud cap drilling (PMCD), where an underbalanced mud (“light annualar mud”, LAM”) is continually pumped down the annulus into a reservoir whilst drilling, allows for safe drilling of highly porous and permeable formations such as carbonate reefs. It has been applied successfully to wells drilled onshore and offshore in Papua New Guinea. The downside of the PMCD technique is high losses of seawater, drilling mud/fluid and cuttings into the formation leading to both porosity occlusion and an altered borehole environment inconsistent with assumptions used in classical log analysis. This makes evaluation of wireline and even logging whilst drilling logs problematic, with difficult determination of porosity and water saturation (Kyi, Han, Lee, Roberts, & Maeso, 2015). Since the initial point at which the bit penetrates the rock is when the rock has had least exposure of time to any invasion, it is proposed that the problems faced by conventional interpretation of electrical logs can be resolved through application of an alternative method that measures mechanical rock properties at the bit as the rock is drilled. This insight is not new. The term “drilling porosity” refers to techniques by which porosity of a formation being drilled could be determined solely from mechanical measurements such as rate of penetration, weight on bit and rotational speed without the need for any separate electrical logging tool. It is no coincidence that the introduction of drilling porosity methods coincided with the advent of computerised mud logging units in the late 1970s which allowed digital recording of surface drilling parameters for the first time. Accurate monitoring and collection of surface drilling data was a necessary component for development of drilling porosity logs. Mud logging companies promoted the use of drilling porosity as a real-time indication of reservoir quality and pore pressure during drilling (Zoeller, 1972). However, details behind the methods used were not published, presumably to preserve competitive advantage. As logging whilst drilling tools gained in popularity the technique has fallen into disuse, and drilling porosity is seldom used by industry today. Bio: Peter Kirkham is the Project Engineering and Commercialisation Manager at Twinza Oil where he helped to rediscover the Pasca A field and shape its development concept over the past five years. He holds degrees in in Engineering from the University of Cambridge and Petroleum Engineering from the University of NSW. Peter specialises in integration of knowledge and data across different technical and commercial disciplines to develop a comprehensive asset understanding.

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2020 AGM - Online for this year. Sept 17, 2020.

Notice is hereby given that the Annual General Meeting of the Society of Petroleum Engineers, Singapore Section shall be held as follows: Date:  Thursday, September 17, 2020 Time:  6:00 pm to 6:40 pm  Venue:  Zoom meeting only  Agenda • Opening address by Section Chairperson • Confirmation of the Minutes of the 2019 AGM held on September 19, 2019. • Officer Nominations for the year to 2021 • Confirmation and Adoption of the Accounts for reporting financial year-end April 1, 2020 • Events update • Membership update • Any other business • To close the meeting To attend please see details below: Time: Sep 17, 2020 06:00 PM Singapore To join Zoom Meeting please email the secretary (PeterMark.Smith@bakerhughes.com) for the link. Passcode: 9VU1d2

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Online Distinguished Lecture: Techniques to Reduce Operating Costs for Increased Reserves and Profit

Philip Hart 6:00 PM Thursday, September 24, 2020   Abstract:    Employing certain practices in past field operations reduced operating costs by over $4.4MM per year and helped increase reserves by more than 3 million barrels of oil (MMBO). These practices are broken into three main topics: Improving expense accounting accuracy and details Focusing on incremental individual operating costs to improve investment decisions Implementing innovative expense reduction techniques   The brief accounting overview concentrates on simplifying invoice coding, creating detailed equipment expenses, and developing more precise allocations. These improvements allow “troublesome” equipment to be identified and optimized, while providing improved financials.   The focus on determining individual operating costs allows shut-in wells to return to profitable production, pinpoints wells losing money, and improves the economics of workovers and new drill wells. Using this approach, one field increased reserves by more than 3 MMBO.   Lastly, nine operational techniques that reduced costs are reviewed in detail (and 10 more highlighted). These applications reduced pumping failures by 61% (saving $2.1MM/year), decreased energy costs by $1.3MM/year, and saved other expenses by $1.0MM/year.   With accurate detailed accounting, incremental individual well cost analysis, and cost cutting efforts, a field’s cash flow and reserves can be increased substantially.   Biography:    Philip Hart, as President of Excalibur Ventures, provides consultations to improve fields through  Reservoir and Operational Studies and also designs oilfield equipment for Omega Technologies in Houston, Tx. He started optimizing fields in 1978 as an Exxon Engineer, taught schools around the world, wrote SPE and SPWLA papers, and was President over companies that operated 2,300 wells. Working with innovative teams, Philip oversaw costs being reduced from $45MM to $25MM per year, while raising production from 13,500 to 19,000 BOPD and increasing valuations from $45MM to more than $300MM. Besides uncovering oilfield gems, he enjoys mission work and family time.  

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Online Distinguished Lecture: Kenneth Decker - Science vs The Art of Gas Lift Confirmation

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Online Distinguished Lecture: Shahab D. Mohaghegh - Subsurface Analytics; Digital Transformation of

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