Singapore Section

Improving Reservoir Simulation Modeling with Seismic Attributes

Abstract – Distiguished Lecture: Seismic attributes are being used more and more often in the reservoir characterization and interpretation processes. The new software and computer’s development allows today to generate a large number of surface and volume attributes. They proved to be very useful for the facies and reservoir properties distribution in the geological models, helping to improve their quality in the areas between the wells and areas without wells . The seismic attributes can help to better understand the stratigraphic and structural features, the sedimentation processes, lithology variations, etc. By improving the static geological models, the dynamic models are also improved, helping to better understand the reservoirs’ behavior during exploitation. As a result, the estimation of the recoverable hydrocarbon volumes becomes more reliable and the development strategies will become more successful. Biography – Dr. Isabela Falk: Isabela Falk is a Senior Geologist, currently the Subsurface Team Leader in a Schlumberger P&AM project in Romania. Previously she worked as a Project Geoscientist for Fugro-Jason in Germany and Holland. Prior to that, she worked as a Researcher Geologist in the Romanian National Gas Company: Romgaz. Isabela holds a PhD in Geology from the University Babes-Bolyai from Cluj-Napoca, Romania, since 2008. She has 20 years of experience in the Oil & Gas industry, specialized mostly in geological modeling, but is experienced also in seismic inversion. She made several scientific presentations in internal and international conferences and is a member of SPE, SEG and EAGE. Dinner and two drinks are provided.

Designing Fit-for-Purpose Facilities in the Current Environment

Joint presentations about facilities design that were given at the recent APE ATW in KL in April. Rolando’s talk is based on actual industry data and performance, and is quite thought provoking regarding why the industry wastes so much capex in its designs. Peter Kirkham   show a case study with  the evolution of Twinza’s Pasca A development over the past couple of years and the “appropriate scoping” into the concept.  Taking Charge in a Low Oil Price Environment Rolando Gachter, Independent Project Analysis Pte Ltd Abstract: High oil prices in the past have bailed out many marginal developments. Waiting for price drops  in  the supply chain to improve today’s opportunities is a passive approach to business success. To survive in a low-price environment requires: (1) a thoughtful and rigorous portfolio management approach; (2) making efficient scope selections; and (3) being smart about development strategies and project practices With this presentation we describe successful lean scoping approaches and sound development  strategies that have improved CAPEX efficiency by over 40 percent. Objectives and scope of  the proposed topic: • To examine why our project scopes have become so inefficient over the last 20 years by  measuring : • How much project scope has grown and explain why it has done so • How inefficient project scopes affected performance • Identify what needs to change in the scope development process and provide a framework  to deliver more competitive project scopes Methodology procedures and process of the topic: • 387 offshore oil projects (recent) for which we have full detailed cost, schedule, production,  and scope details were examined • Root causes of performance were established from detailed review of the project case  histories • Causes (and effects) of scope inefficiency are calculated Observations and conclusions of the proposed topic: • Weight increases over time for almost identical pieces of scope can be demonstrated. There  are three main drivers of inefficient scope decisions: • Systematic subsurface over-confidence • "Intense" reservoir depletion strategies • Increase risk aversion Recommendations to address these root causes are presented. Biography: Mr. Gächter has over seventeen years of capital project benchmarking experience, specializing in energy and minerals extraction projects. His experience includes large-scale project system benchmarkings for major oil and natural gas producers. His experience also extends to reviews of over 100 major capital projects worldwide in the petroleum exploration and production and mining sectors covering over $5 billion in capital expenditures. Mr. Gächter has managed the accounts of a diverse group of clients both big and small. These include a supermajor , a large national oil company, as well as smaller independent operators. He currently serves as a senior instructor of the IPA Institute which provides education to project professionals globally. Over the years Mr. Gächter has presented at various industry conferences and seminars including the United States, Europe, Africa, and the Middle East. Establishing Appropriate Development Concept and Cost – Pasca A Case Study Peter Kirkham, Twinza Oil Abstract: The days of $100+ oil are behind us (for now), but their legacy continues to live on in the development concepts and engineering practices that the environment spawned. In the rush to develop in the decade from 2003 to late 2014, oil and gas project costs spiraled out of control. There are many reasons for these increases such as cost escalation, poor project practices resulting from an overstretched industry, increasingly stringent engineering specifications, and perhaps most simply: high demand for limited contractor services. When considering the capital costs to use for exploration economics, it is common to use benchmarks, or perhaps a high-level factored cost estimate based on industry norms, unit rates and similar concepts used previously. But how relevant are these benchmarks today? If we just take conventional approaches to field development and base our capital cost estimates on historical data (thinking that it’s all we have, so we have to use it), then we consign ourselves to a conservative mindset. Exploration requires creative thinking, and without it no-one would ever imagine a new play system or dare to drill an exploration well. The economics to support such endeavours require a similar mindset. The Pasca A development offshore PNG started concept engineering in October 2014, just as the oil price began to fall. Unlike many other developments, the project was not shelved, and continues towards development. One of the reasons for this is the “fit-for-purpose” development philosophy that was adopted. Approaches taken during the Pasca A project are used to illustrate aspects of project development that others might adopt in a low price environment. • Clear objectives: Know where you are heading and the development priorities. • Integra ted team: Working together to deliver an optimised concept requires multi-discipline  knowledge and communication – particularly for those running the economics at the heart of  the project. • Keep scope under control: Don’t over-design; identify and quantify the trade-offs that result  from cutting scope. • Appropriate design requirements: Using off-the-shelf design and designing to industry  standards rather than bespoke solutions saves cost. • Collaborate with contractors: easy to say, harder to do, but keeping an open mind to  alternative concepts and embracing solutions that meet the functional requirements. • Understand the economic drivers: increasing NPV is not necessarily the best outcome. Biography: Peter is a petroleum engineer with 17 years industry experience across multiple engineering, technical and commercial disciplines. He is a member of the Society of Petroleum Engineers and currently serves on the committee for the Singapore Section. He started his career at Novus Petroleum as the Commercial Assistant to CEO and helped manage all aspects of a portfolio that included exploration, development and production operations for assets in Australia, Indonesia, Egypt, Pakistan, Oman and the United States. He was subsequently involved in the founding of Lodore Resources in 2004, a London-listed oil and gas explorer which drilled three exploration wells in the United States, two of which discovered gas. Peter was a Senior Project Analyst at Independent Project Analysis where he was involved in the evaluation of more than 65 oil and gas project developments ranging in size from 10s of millions to 10s of billions US dollars , and encompassing a wide variety of development concepts and countries. Today Peter is the Project Engineering Commercialisation Manager at Twinza Oil, based in Singapore. In this role , Peter oversees Twinza’s Pasca A project development in offshore PNG, and has been involved in most aspects of the project since early FEL 2.  

Upscaling Formation Damage Laboratory Test Data to Full Well Perspective

Abstract: The impact of formation damage on overall well productivity or injectivity depends on the magnitude and distribution of the damage. Computational Fluid Dynamics (CFD) simulation provides a means to upscale suitable laboratory test data to quantify the impact of formation damage on well performance, by representing the degree of restriction and the geometry of the damaged zone or zones in a full well simulation. Different magnitudes of damage derived from laboratory test data can be simulated and the impact on overall well performance predicted for different completion environments. This presentation will illustrate some applications of CFD modelling to upscaling of laboratory measured formation damage, and attempt to tackle the issue of the interface between well construction and well deliverability.   BIO: Rick Lemanczyk is Principal Petroleum Engineer in Lloyds Register Energy’s Consulting Division, based in Kuala Lumpur, and has a career spanning over 39 years in various aspects of production technology.  After graduating with a D.Phil. in Physical Chemistry from Oxford University, Rick began his oilfield career with Schlumberger from 1977-1992 in a variety of positions: wireline engineer, well stimulation R&D department head and regional laboratory manager. Between 1994 -2006 he worked for Edinburgh Petroleum Services Ltd. ( now a Weatherford company), providing technical support, business development, consulting and training in the areas of production optimization, artificial lift, sand management, well stimulation, completion analysis and formation damage.  In LR Senergy Rick’s current role is to coordinate the company’s rock properties and production chemistry activity in the Asia Pacific region.  Throughout his oilfield career Rick has conducted many training courses and lectured widely on Production Technology subjects. In 1992-94 he was a Senior Research Fellow at Heriot-Watt University in Edinburgh, and in 2016-17 Adjunct Professor at Heriot-Watt’s Malaysia campus. He was nominated as an SPE Distinguished Lecturer in gas lift optimisation for 2010-2011.

Baker Hughes - GE merger (AIPN/SPE joint event)

This is a joint event with the AIPN, with speeches from two guests of honor: Mr Nathan Meehan and Mr Visal  Leng The Baker Hughes and GE Oil & Gas merger has been called "the most transformative combination in modern oil and gas history."  Coming on the heels of a failed attempt by Halliburton to acquire Baker Hughes, this deal is unique in terms of deal structure and objectives. Visal Leng, Asia Pacific President of Baker Hughes, a GE company and Dr. Nathan Meehan, 2016 SPE President and President of Gaffney, Cline & Associates will go over the context, history and goals of this merger. 

YP Visit of the Multiphase Flow Loop at the NUS

Hello YPs (that's for Young Professionals)! As part of the SPE's mission, we are enabling learning opportunities for Petroleum Engineers. This includes visits to facilities not normally accessible to you. The Multiphase Flow Loop is used heavily for Flow Assurance Research work involving multiphase transportation of oil-water-gas mixtures and also the flow regimes and slug loading on both offshore and onshore pipelines. Videos of the flow regimes generated through various compositions of oil-water-gas mixture are used in the Offshore Oil & Gas Technology module lectures. Grab this opportunity, and join us for this visit of the Multiphase flow loop at the Centre for Offshore Research and Engineering at the NUS. You can ask questions on our  Facebook group In the document attached to the Facebook event you will find a description of the facilities. The visit will last 1 hour  from 12 to 1PM , then we will go for lunch to network and socialise . We will meet up at the street level at 1, Engineering Drive at 11:45AM. Please be on time, as this is a short visit, with a tight schedule. To register please send your name, FIN Number, organisation , email, phone number to the contact email address. The numbers are limited so please register early, and do update your status if you cannot make it, so that we inform those on the waiting list.

PNG: Recent appraisal, exploration highlights and technological implication in foothills exploration

William Gordon-Canning, Total PNG Exploration Manager, will cover an overview of Total’s current E&P activity on PRL 15 and how exploration and appraisal activity is optimised with the use of global experience and technological advantage.  Total is present both within the M&S and E&P branches within PNG with presence in M&S since 2012 and E&P since 2014 with the closing of Total’s entry to the PRL15 license. Total’s E&P activity in PNG covers both exploration and appraisal activity in the Onshore PRL 15 license as well as Deep and Ultra Deep Offshore Exploration in the recently awarded PPL 576 license. This presentation will focus on activity within the PRL15 license where Total operates activity with 40.13% interest with joint venture partners Oil Search and InterOil*. PRL 15 hosts the ElkAntelope Field, one of the most significant discoveries in Asia over the last 20 years. The license lies within a fold and thrust belt domain and approximately 120km inland from the township of Kerema and 360km northwest from Port Moresby. The location within a complex fold and thrust belt leads to significant subsurface and operational difficulties. This presentation will aim to provide an update to Total’s position in PNG and a recent appraisal update on the Elk-Antelope Field as well as discussing the forward exploration potential of the license. We will also address how Total tackles the operational complexities in such a complex environment by optimising technological input and global foothills experience. Final appraisal is under completion with the recent drilling of the Antelope-6 and 7 wells in 2016 and early 2017. Antelope-6, located to the eastern flank of Antelope, has been drilled to aid definition of the eastern extension of the reservoir. Top reservoir was encountered shallower than prognosis and the well proved dolomite presence as per prognosis. Antelope-7, located to the West of Antelope-5 on the western field margin was drilled to assess the limit of the carbonate reservoir on the western flank of the structure. Additional exploration potential remains significant on PRL 15 and Primary exploration focuses on Miocene carbonates equivalent to the reservoir of Elk-Antelope. A number of further exploration targets have been identified for near term drilling and maturation with additional data acquisitions. The complex strucuration results in difficult data acquisition and resulting imagery. Total has significant global foothills experience combined with onshore operational expertise. For optimal prospectivity de-risking over PRL 15 Total uses modern technology and data acquisition advantages. Recent and additional future activity includes, in-house 2D seismic PSDM reprocessing, high resolution surface imagery, airborne gravity gradiometry, Magneto- telluric techniques, and processing technologies combined with detailed geological studies using in-house experts and collaboration with global and joint ventures experts. * Acquired by ExxonMobil

Distinguished Lecture Dave Stern: Creating Geologically Realistic Models Used for Reservoir Manageme

Creating Geologically Realistic Models Used for Reservoir Management Dave Stern ExxonMobil Upstream Research Company Abstract To make sensible reservoir management decisions, it is necessary to predict future reservoir performance.  This allows testing and optimization of reservoir management strategies before making large investments.   When displacement mechanisms change or geologic description is different from current well locations, this prediction is usually done with reservoir simulation models.   Because geologic features determine the connectivity and productivity of the reservoir, it is important to ensure that models realistically represent the reservoir description in order to provide plausible predictions.   Challenges associated with constructing these models include: Uncertainty in the geologic description – measurements are sparse, and do not always resolve the relevant features . It isn’t always known which features are relevant to reservoir performance.   Geometry and stacking of geologic objects like channels and lobes are difficult to represent in cellular models Multiple descriptions may exist that are consistent with available data This presentation describes how reservoir models are used in making reservoir management decisions, and outlines a strategy for creating realistic reservoir models.  Examples are provided of applying some elements of this strategy. Biography Dave Stern is a career researcher at ExxonMobil’s Upstream Research Company (URC) He joined URC in 1984 with a PhD in Chemical Engineering from University of California at Berkeley and a BS in Chemical Engineering from MIT.  Research areas include experimental measurement of gas injection performance, development and use of simplified models for reservoir management, gridding and scale-up, and history matching. He led a team that developed tools for construction of simulation models from detailed geologic models, worked with software developers to implement that technology, and trained the rest of the corporation in its use.   Dave is the author of an SPE distinguished author paper on practical aspects of gridding and scale-up, describing learnings from that experience. Dave also led a team that developed tools and methods for history matching, with emphasis on preserving geologic realism during the history match process.   The team worked with software developers to implement the tools, and trained the rest of the corporation in their use.   He is currently a Reservoir Engineering Advisor to a large project that develops and maintains software for reservoir modeling and simulation. Dave is a career-long member of SPE, and has served as session chair or discussion leader in SPE forums on gridding and scale-up, reservoir modeling for asset teams, and data analytics.  

Distinguished Lecture: Developments in Heavy-Oil EOR for the Era of Low Oil Pricing

Developments in Heavy-Oil EOR for the Era of Low Oil Pricing         Jose Gonzalo Flores Abstract In low oil-price environments, it is customary to cut expenses, reduce staff and postpone most, if not all, capital investments. While this strategy may be financially sound in the short term, it completely disregards the essence of the oil business, that is the timely replacement of reserves. The problem further complicates in the case of heavy oil projects, where costs are higher and the product price is even lower. This presentation confronts the audience with the dilemma of reducing cost and at the same time sustaining production and increasing recoveries. The balance resides in the quality of decisions, such as when and where to invest, and that results meet budgets, a common issue in our industry. In the most complex and financially challenging case of Enhanced Oil Recovery (EOR) projects, decision quality in combination with “fit-for-purpose” technology implementations offer the most promising middle-point, this is the central idea in this presentation. By providing 8 examples of innovative technologies to help reduce uncertainty, cost and time for commercial EOR oil, and 3 successful case studies, the audience will gain confidence in the proposition that is perfectly viable to double recoveries in the next 15 years. Finally, EOR is a business, as such, it needs to compete favorably in cost and time with other alternatives present in a company’s E&P portfolio, particularly in low-price environments. A strategy, illustrated by an example, on how to divert from the traditional engineering approach in favor of a managerial decision approach will help engineers justifying viable recovery projects Biography Jose Gonzalo Flores is an independent consultant and instructor in the areas of production and reservoir engineering of heavy oils.  Previously, he worked for Schlumberger and Occidental Petroleum Corp. covering a 30-year period, in roles involving the structuring, leading, advising and field implementation of production optimization and improved recovery projects, and as instructor for NExT, globally.   Flores holds a B.S. degree from the Universidad Nacional de Ingeniería, Lima, Peru, and M.E. and Ph.D. degrees from The University of Tulsa, Tulsa, Oklahoma, all in Petroleum Engineering.   He is considered an expert in the areas of reservoir and production enhancement and strategies to increase the recovery factor in heavy oil and mature fields, and has over 45 publications in the literature.   Flores is a member of the SPE, and regularly serves in steering and technical roles in conferences, forums and workshops.   Currently, he serves in the SPE Editorial Review Committee and as co-chair of the 2016 SPE Latin America Heavy Oil Conference.