Details 2001 - 2002
Abu Dhabi SPE Section 2001-2002 Events
October 1, 2001
Dr. Bjorn P. Wygrala
Dr. Bjorn P. Wygrala: Born and educated in Australia. Diploma (equivalent to MSc) in Geology acquired at the University of Cologne, Germany, followed by a Ph.D. in Geology and Petroleum Systems Analysis, also at Cologne University, in a joint project with Agip, Italy.
Professional Experience: Started with 3 years of field experience in Sedimentology and Basin Analysis for the minerals exploration industry, followed by more than 15 years of experience in basin analysis and the application of simulation technologies for petroleum exploration companies in more than 30 countries.
Scientific Interests: Applied petroleum systems modeling, quantification and sensitivity analysis of geologic parameters and processes in petroleum exploration. Present Affiliation and Position: VP Technology Transfer at IES Integrated Exploration Systems, Juelich, Germany.
3D Petroleum Systems Modeling - The Big Picture !
Can you imagine a complete 3D geological model of onshore-offshore Abu Dhabi, or of the entire Ghawar drainage area in Saudi Arabia or of the vast Alaska North Slope? A model which contains details down to reservoir scale and in which processes in the entire petroleum system are modeled from source to trap? A model which can be ‘paged’ backward and forward through geologic time to study the entire history of a basin. And a model which uses advanced multi-phase, incomponent simulation methods such as flash calculations in order to understand and predict hydrocarbon locations and
properties. This is 3D Petroleum Systems modeling, a relatively new technology which has only entered the market during the last two years, but is already being deployed in most of the world’s basins in both exploration and production settings.
The presentation will introduce the technology, describe how and why it works, and how it is used. Geologists and geophysicists will see what can be done with rigorous data management procedures, and reservoir engineers will see how
their methods have been upscaled to be used in regional scale geological models. The goal? To provide a tool and a methodology which will help geoscientists in E&P work in both frontier and mature basins to understand and then to improve predictions of hydrocarbon behaviors and properties in entire petroleum systems.
October 9, 2001
Dr. Muhammad Al-Marhoun (Distinguished Speaker)
Muhammad Ali Al-Marhoun is a professor and former chairman of the Petroleum Engineering Department at King Fahd University of Petroleum and Minerals, Dhahran, Saudi Arabia. He received his Ph.D. in petroleum engineering from the University of Oklahoma, Norman, Oklahoma, his MS in mathematics and BS in general engineering from King Fahd University of Petroleum and Minerals. He has published several research and technical papers. He is a member of the Society of Petroleum Engineers.
Reservoir Fluid Properties - State of the Art and Outlook for Future Development
Knowledge of reservoir fluid properties is a fundamental requirement for all types of petroleum calculations such as determination of hydrocarbon flowing properties, and design of fluid handling equipment.
This presentation provides a review of the state of the art of the reservoir fluid properties and outlines the outlook for future development. The review provides an overall look to the current status of how these properties are obtained, related shortcomings of these methods, and the overlooked aspects of current fluid properties measurement and calculations. The future development must tackle the shortcomings and address the over looked aspects.
This lecture addresses the title subject though the discussion of the following issues:
- The reservoir process is not yet represented in our laboratory tests. Is it flash, differential, combination or some thing else?
- There is no direct experimental procedure to measure Bo, Pb, Pd, etc.
- The smoothing method utilizes only part of the data. This is clear in the Y-function.
- Laboratory reports should include the raw data to check the accuracy of the smoothed ones.
- The correction of the differential data to separator conditions does not honor the reservoir conditions.
- Oil compressibility correlation does not observe physical trend. Some oil compressibility correlations are based on wrong pressure - volume data.
- The regression methods used in obtaining correlations assume that data for the independent variables are exact while they are not.
- The fluid composition could not be explained by gross properties.
- The errors in some PVT properties calculations are not acceptable.
- Water properties are not well studied.
- Is the neural network the ultimate solution?
- The calibration of EOS is localized.
There are challenges in addressing these problems, certainly, but there are untapped scientific tools as well. The discussion will explore these challenges, examine the possible solutions and suggest a course of action.
November 11, 2001
Pat McGuire
Mr. Pat McGuire is the principle technical advisor within BP on WAG processes and a distinguished SPE lecturer. He has 20 years experience working on miscible gas injection at the Prudhoe Bay Field, which is the worlds largest EOR WAG flood. He is a co-founder of the original process from conception to implementation. He has been the principle driver of EOR research for Prudhoe Bay and also had a fudamental role in driving operating plans for its implementation. He has also been responsible for developing WAG monitoring processes and observation techniques to establish displacement efficiencies. He has developed numerous non-conventional WAG operational applications in waterflooded reservoirs.
EOR Projects - 'How Do I Design One That Works ?'
Taken from his lecture series ' Everything You Wanted To Know About EOR But Were Afraid to Ask' the presentation will cover the critical features of a miscible gas project.The talk will cover some of the miscible displacement mechanisms, the types of problems that lead to creative solutions, field eamples, and an analysis of typical problems encountered in an EOR project.
January 6, 2002
John Pringle
John Pringle is a Petroleum Engineer with a Masters Degree in Petroleum Engineering from Heriot Watt University. John currently works as a Managing Consultant for Landmark based in Dubai where his main role is to assist operators optimize production by improving their Production Management Systems. John has 15 years industry experience gained with large and small operators in the North Sea and Middle East as well as experience with technology service providers.
Development Scenario Analysis (DSA)
DSA is a process designed to improve development decisions by encompassing risk and uncertainty into the evaluation process. Traditionally projects have been evaluated on the best, most precise technical model using a single set of economic results. The DSA process involves taking a stochastic approach using Monte Carlo simulations to account for technical, economic, political and other uncertainty. This results in many analysis being run in a short time with a distribution of likely outcomes. This enables managers to compare projects which might otherwise have similar NPV’s in terms of their potential upsides or downside risks, which helps to select the projects which generate the greatest returns with the minimum downside risks.
January 26, 2002
Andrew Carnege
Mr. Andrew Carnegie is a Principal Reservoir Engineer, Schlumberger, Gulf Region. He holds B.Sc in Applied Maths, PhD Mathematical Physics ("Chaos Theory"), London University.
Mr. Carnegie Worked for the last 12 years for Schlumberger, as a reservoir engineer, geostatistician, software developer and research scientist, at various worldwide locations. Before Schlumberger, he worked for 4 years for ECL (bought by SLB!) performing ECLIPSE support and reservoir engineering consultancy. Before ECL, Andrew worked for 3.5 years for Sema group (also bought by SLB!) as mathematician and software analyst, with focus on torpedo and submarine design.
An Advanced Method of Determining Insitu Reservoir Stresses; Wire line Conveyed Micro- Fracturing
Interest is rapidly growing in obtaining reservoir geomechanical data such as the insitu stresses and rock strengths, since it is now realized that they are important to a wide range of applications; from bore hole stability through to well stimulation through to reservoir management issues such as optimal placement of water injectors and oil producers. Reservoir stress magnitudes can be inferred by continuous logs, for example by sonic based measurements. But these must be calibrated to direct measurements of stress. At present the only reliable, accurate measurements of insitu stress come from micro-fracturing. This talk describes a recently introduced, microfracturing technique, based on the MDT*, which yields high quality stress information, and is more cost effective to employ than any other commercial micro-fracturing technique.
After an introduction to applications of geo-mechanical measurements, the relevant principles of the MDT* tool will be described. Following that, the theory and application of micro-fracturing with the MDT* will be illustrated by an example in which reliable estimates of stress magnitudes, and lower bounds of rock tensile strengths, were obtained in an Abu Dhabi reservoir. This is the first example of any stress test which has been performed by micro-fracturing in a limestone reservoir. Then, so as to allow the audience an understanding of the feasibility of the technique, the talk will conclude with a summary of best practice guidelines for planning and running MDT* minifracs. Included in this will be recommendations on how the MDT* can be combined with sonic, imaging and caliper logs to gain other valuable data related to stress, such as principle horizontal stress directions, and continuous depth vs stress profiles (minifrac can only give point wise data).
February 10, 2002
Jim Vendito
Precise Fracture Initiation Using Dynamic Fluid Movement allows Effective Fracture Development in Deviated Wellbores
In deviated wellbores with long perforated intervals, conventional fracture initiation with wellbore pressurization often creates multiple fracture initiations, resulting in severe fracture tortuosity. When this happens, treatments are generally plagued with high injection pressures, low injection rates and, quite often, early screenouts. One solution to the problem of multiple fractures is to use the fluid’s own dynamic movement to divert flow to a specific point. This method accurately positions and directs fracture initiation. With proper planning, a single fracture can be initiated and proppand can be easily placed without tortuosity effects.
This paper discusses the use of the dynamic fluid movement treatment in a well positioned on an incline through the pay section. Premature screenout had occurred when proppant first entered the formation on a previous treatment attempt, and fracture modeling indicated that multiple fractures were the apparent cause of the screenout. When the dynamic fluid movement method was used on a subsequent treatment, a fracture was initiated properly, and a large proppant treatment was placed successfully.
March 2, 2002
Dr. Fikri J. Kuchuk
Dr. Fikri J. Kuchuk, Schlumberger Fellow, is Chief Reservoir Engineer for Schlumberger Oilfield Services in Middle East and Asia. Before going to the Middle East, he was Senior Scientist and Program Manager at Schlumberger-Doll Research Center, Ridgefield, Connecticut, US. He was a consulting professor at the Petroleum Engineering Department of Stanford University from 1988 to 1994 and taught Advanced Well Testing. Before joining Schlumberger in 1982, he worked on reservoir performance and management for BP/Sohio Petroleum Company. He has an MS degree from the Technical University of Istanbul, and MS and Ph.D. degrees from Stanford University, California, all in petroleum engineering.
Oil Recovery and Multiphase Flow Formation Properties
In spite of many recent a advances in reservoir characterization and simulation technology, oil recovery factors has not increased significantly and production forecasts are still not very reliable. In the most widely used secondary oil recovery, injected water into the formation sweeps oil towards the producer as well as maintains pressure. At least 45 to 55% of oil should be recovered by water flooding, actual recovery numbers are much lower. Reservoir heterogeneity is of the main reasons for the low recovery oil factor. As stated by K. J. Weber: "Projects undertaken without detailed reservoir evaluation often end in failures related to unexpected baffles to flow, permeability heterogeneity, or wrong appreciation's of the residual oil distribution." Spatial variation of the reservoir rock properties (heterogeneity) strongly affects the sweep efficiency, with the injected fluid tending to channel towards the producer along those paths offering least resistance (high-permeability streaks). To determine recovery factor as well as to make production forecasts, the spatial variation of rock and fluid properties, such as porosity, permeability relative permeabilities, residual oil saturation, etc. are need for reservoir simulation.
In my presentation, first I will talk about in-situ determination of oil-water relative permeabilities and recovery factor using near-wellbore (more than a few meters) formation dynamic and static data. A methodology will present for integrating local transient pressure test and water-cut measurements with openhole array resistivity measurements to obtain relative permeabilities of oil and water.
Second, I will talk about a large-scale field experiment (about 40 to 50 meters) where we used a recently developed downhole setup to determine the oil recovery factor and relative permeabilities to oil and water in a Middle East Carbonate reservoir. In this experiment, we continuously monitored downhole pressure and deep formation resistivity as well as wellbore production profile.
March 25, 2002
Ron Deady
Ron Deady is the Global Product Champion for Sperry-Sun Halliburton's Bi-Modal Acoustic (BAT™) tool based in Houston. Ron has been involved in M/LWD for over 20 years working for various service suppliers in engineering, product development, and petrophysical support roles in both domestic and international assignments. He holds a degree in Geology and is a member of the SPWLA.
Reconciling Geophysical Data with a Next Generation Logging While Drilling Acoustic Tool.
Several differences exist between LWD and wireline logging environments. When making acoustic measurements the LWD environment is inherently noisier then when wireline logs are run, the drill collar supports additional propagation modes, the data are obtained at irregular depth intervals, and tool centralization is generally poor. Furthermore, it is difficult to achieve a pure monopole or pure dipole transmitter mode in LWD tool configurations; this complicates slow shear measurements based on flexural or Stoneley interface modes. To address the added complications of LWD sonic logging, new processing and analysis techniques have been developed for use with a second-generation LWD sonic tool. In addition to the standard slowness vs. arrival time coherence computation, the frequency, energy, delay, and attenuation of each coherent arrival is also computed. These properties can be examined at each acquisition to determine the properties of the desired compressional, refracted shear, and interface modes.
With the ability to determine compressional, refracted, and slower than fluid shear delta t data and, therefore provide Poisson's ratio throughout the well additional interpretation applications become possible. One such application is the use of LWD data in an amplitude vs. offset (AVO) analysis. This presentation will begin by discussing the LWD acoustic tool and show examples from various formations and borehole environments illustrating the use of the multi-parameter analysis approach to LWD sonic log processing. We will also show several field datasets and a specific example of the use of LWD acoustic data in validating the assumption set used in a surface seismic AVO analysis.
April 9, 2002
Mark Cook, SPE Distinguished Speaker
Mark Cook (BSc,MBA) has worked in the petroleum industry for 20 years; 11 of which were for Shell International, and 9 with TRACS International. With Shell, he worked as a reservoir engineer in Holland, Oman, Tanzania, London and Aberdeen, gaining experience of prospect evaluation, field development planning and management of producing fields, and finally as an instructor in the Group's training centre.
In 1992, he set up TRACS International, presently employing 25 and providing training and technical consultancy to the industry. He is Managing Director of TRACS International Consultancy and a Director of TRACS International Training Ltd, and continues to be active in both training and hands-on consultancy. His main areas of interest lie in reservoir engineering, petroleum economics and risk analysis, subjects in which he has developed and delivered training courses to advanced level. For the last five years, he has run the SPE Short Course in Petroleum Economics. He is co-author of "Hydrocarbon Exploration and Production", Elsevier, 1998, which has sold over 5,000 copies.
Use and Abuse of Economic and Risk Indicators in Upstream Projects
A regional exploration manager has been given the annual performance target of adding 50 MMb to the corporate reserves base. He has two basin options from which to select.
· Basin A has a prospect with a most likely reserves volume of 200 MMb, and a probability of success of 10%.
· Basin B contains five smaller prospects, each with a most likely reserves volume of 10 MMb and each with a probability of success of 40%.
He can afford to drill up to five exploration wells, but must commit to either Basin A or Basin B. Which does he select?
Many will select Basin B, on the basis that two out of five of the prospects will be successful, and 20 million barrels will be discovered. This will not meet the performance target but is perceived to be the less risky option, despite both basins having equal risked reserves. The high-risk, high-reward prospect will be neglected, but at least something is found! Extrapolating this choice to all of the exploration regions of the company will result in conservatism, giving the company a low-risk, low-reward prospect inventory.
The attitude to the problem varies with company size. The concept of utility theory describes, using simple examples, how attitude to risk varies with circumstances. Investment options are typically ranked using discounted cash flow techniques and indicators such as internal rate of return (IRR), net present value (NPV), and efficiency ratios of NPV per unit of investment. In times of cash flow difficulty, simpler indicators such as payback are invoked to favour projects that rapidly generate cash with which to meet shareholders' expectations.
This talk will discuss examples of the inappropriate use of traditionally popular economic indicators and assumptions, in both exploration and production decisions. The above is one such example.
April 27, 2002
Bruce Parker
Bruce Parker is the Technical Marketing Manager for Cameron Elastomer Technology (CET), Katy, and Texas USA. CET is part of the Cameron Drilling Systems Business Unit, Cameron Division of the Cooper Cameron Corporation, Houston, Texas, and USA. Bruce is responsible for providing the technical interface with Cameron customers on Cameron's high performance Elastomer products and coordinating the introduction of new drilling Elastomer products. These elastomers are primarily used in drilling products, but also used in production equipment where long trouble free life is a requirement.
Bruce holds a Bachelor of Science in Mechanical Engineering from Lehigh University, Bethlehem, Pennsylvania and has completed a course of study at the Rice University Advanced Management Institute. He is a member of The American Society of Mechanical Engineers and The Energy Rubber Group, Rubber Division, American Chemical Society. Bruce has been with Cameron for the past 17 years and has authored numerous technical papers dealing with drilling Elastomer issues and Elastomer life prediction. Let me know if this is what you need.
Mark Svoboda
Mark Svoboda is the Engineering Manager for Cameron Middle East - North Africa Region. Based in Abu Dhabi, Mark is responsible for providing conceptual design solutions, local product engineering, technical and field service support for customers in the region. Mark holds a B.S in Mechanical Engineering from Texas A & M University, Texas, USA. With a career starting in Houston, Texas in 1982, under the surface wellhead engineering department, Mark moved into the international scene in 1991 to provide a wide range of engineering and field service support functions in Southeast Asia, and for the last 4+ years, the Middle East
High Temperature and H2S Resistant Elastomer used in Cameron Drilling Products
Over the past 20 years, Cameron has conducted extensive elevated temperature research, development, and testing of elastomers for use in drilling products. Starting in 1982 with the establishment of Cameron Elastomer Technology as a research, development, testing, and manufacturing facility, Cameron has been dedicated to offering the highest performance Elastomer for its drilling product line.
In this presentation, we will review the development and verification testing of various high temperature and H2S resistant Elastomer compounds and the integration into the Cameron Drilling Product line. Some items to be covered are CAMLAST(tm) and DUROCAM(tm) elastomers, CAMRAM 350 packers and top seals, variable bore ram packers (VBR and VBR-II), FLEXPACKER and FLEXPACKER-NR, and high temperature shearing blind ram (SBR) packers.
The presentation will illustrate how through an active R&D and testing program, improved Elastomer products have been able to safely extend the capability of our drilling products.
Original Equipment Manufactures (OEM) Repair Philosophy
In order to keep up with the industry as we continue to push the drilling boundaries further and further, risk management, HSE and technology must also change. Since drilling and well control equipment in the field provides long and useful lives, periodic inspection, maintenance, refurbishment and traceability is instrumental in reducing drilling site risks and providing a safe and healthy work environment. Original Equipment Manufactures (OEMs) perform an essential role in obtaining this goal. This presentation will address industry specifications for refurbishment, benefits of OEM refurbishments and refurbishment limitations.
May 4, 2002
Dr. Thomas Finkbeiner, GeoMechanics International, Inc.
Thomas Finkbeiner started his career in Geophysics at the University of Karlsruhe, Germany. In 1992, he enrolled in the geophysics department at Stanford University from where he received his Masters in Exploration and Development in 1994 and his Ph.D. in 1998. Since the fall of 1998 Thomas has been working for GeoMechanics International as a specialist in reservoir geomechanics and consultant for the petroleum industry in wellbore stability and in situ stress. Since 2001, he has been assigned to the Middle East to provide services to regional operators and clients.
The Role of Geomechanics during Drilling and Production
Geomechanics has a profound impact on a variety of activities related to drilling and production. Using examples drawn from case studies in oil and gas fields around the world, we demonstrate how one can design an optimal drilling and completion program that eliminates or minimizes mechanical instabilities of the wellbore, by considering the interaction of the stress field, pore pressure, natural fractures, rock strength, mud weight, and wellbore trajectory. Drilling problems such as sloughing, stuck pipe, bridging and others occur due to severe mechanical instabilities of the wellbore wall when the stress concentration around the wellbore substantially exceeds the strength of the rock. This type of problem can be exacerbated by slip on weak bedding planes in finely laminated shales. We demonstrate how these types of problems have been successfully addressed by raising the mud weight or drilling in an optimally stable trajectory. Drilling problems associated with lost circulation on the other hand often occur due to the mud weight exceeding the least principal stress and tensile strength of the wellbore wall. Thus, a key consideration in optimal well design is to use optimal mud weights. The so-called 'mud window' defines mud weights to be sufficiently high to guarantee wellbore integrity, but no higher than necessary in order to avoid circulation losses. We will demonstrate how establishing the appropriate mud window is done using analyses techniques based on geomechanical principles and, in addition, quantitative risk assessment to incorporate all of the uncertainties in the various components of a geomechanical model. The same geomechanical principles apply with respect to sand control. During reservoir production, wellbore instabilities and solids production (e.g., wellbore sanding) can be successfully controlled by choosing optimal levels of reservoir depletion, wellbore drawdown, or optimally oriented perforations. In all situations an accurate geomechanical model of the reservoir or field is essential for determining the appropriate mud window, well trajectory, or potential for solids production during depletion. This presentation will provide an overview of the basics of geomechanics and will demonstrate the power of geomechanical modeling for solving problems related to wellbore stability problems.
May 19, 2002
Professor Andrew W Woods
Present Position: BP Professor of Petroleum Science and Head of BP Institute, University of Cambridge (also Professorial Fellow, St Johns College, Cambridge)
Research Interests: Professor Woods carries out research using theoretical, experimental and numerical techniques. He has particular interests in flows in porous rocks, especially related to the hydrocarbon and geothermal industries, including research into the effects of phase change, mixing, instability, thermal anomalies and gravity on multiphase flows in porous rocks. He also conducts research into multiphase turbulent flows especially those with geo-relevance, including sanding flows, turbidite and ash flows, bubbly flows including both pipe-flow and unconfined flows such as arise in the ocean, atmosphere or lakes. He also has interests in low energy building design and natural ventilation flows.
Major Prizes: Mayhew Prize, Univ of Cambridge, 1986. Smith Prize, Univ of Cambridge, 1988. Italgas Prize, Turin, Italy, 1997. Marcello Carapezza Prize, Rome, Italy, 1997. Wager Medal, Martinique, France, 2002
Previous Appointments: 1996-1999: Professor of Applied Mathematics, University of Bristol, UK. 1991-1996: Lecturer in Applied Mathematics, University of Cambridge and Teaching Fellow, St Johns College, Cambridge. 1989-1990: Green Scholar, Scripps Institution of Oceanography, La Jolla, California. 1989: PhD in Fluid Mechanics, Department of Applied Mathematics, University of Cambridge
The Important Effects of Gravity on Flows in Porous Media
In this lecture I will summarise the results of some recent research at the BP Institute in Cambridge (www.bpi.cam.ac.uk) exploring the effects of injecting water of one temperature into a reservoir of different temperature, with a view to displacing hydrocarbon. We will focus on the dynamics of the thermal front which lags behind the injected fluid front. First, we will explore the control of the temperature change on the density of the injected fluid, and hence the shape of the spreading plume of liquid. Theoretical models will be compared with novel laboratory experiments, revealing the potential control of temperature on the shape of the flood front. We will then explore the structure of thermally induced reactions which may arise as liquid of one temperature is injected into a reservoir with a second temperature, possibly leading to changes in permeability of the formation. Finally we will examine how the results of this research can impact the strategy for production of a reservoir, illustrating the discussion with an example from the North Sea.
May 26, 2002
Paolo Ferraris - Schlumberger
Paolo Ferraris is Schlumberger Interpretation Development Principal Petrophysicist for the Gulf region, located in Abu Dhabi. He joined Schlumberger in 1982 as Field Engineer with Flopetrol and had several assignments in Brazil, Venezuela, Libya and Italy, both in field and technical management before moving to Wireline and Testing in 1987. During subsequent assignments in France, Italy, Norway and the UAE, Paolo became involved in the field testing and commercialization of many new wireline tools and acquisition systems available today. In 1998 he was appointed Senior Petrophysicist in Qatar and in September 2000 he returned to the UAE to support Petrophysics and CHFR* in particular for the Gulf Geomarket. Paolo is a graduate of Politecnico di Torino, Italy , holding an MS degree in Electronics Engineering.
The second generation of Behind Casing Formation Resistivity Measurements: pushing the challenge ahead
The ability to measure formation resistivity behind steel casing has been a major goal in the oil industry since the 1930s. In spite the measurement theory
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