Is it Artificially Intelligent? Application of Probability Pruning by Filtering in Petrophysics (click for paper)
Mirano Spalburg, Consultant.
Log evaluations to estimate formation properties such as porosity and saturation are often deterministic, the uncertainty being estimated with a partial derivatives scheme or a Monte Carlo scheme around the calculated property values. Almost inevitably the results exhibit high sensitivity to evaluation parameters such as grain and fluid density and failure to acquire data for one of the logging tools used in the evaluation scheme can cause considerable concern. Uncertainty is usually only estimated in the neighbourhood of the calculated formation properties. In Bayesian uncertainty reduction, by contrast, a range of possible formation properties is defined by a (team of) specialists and subsequently reduced by one or more logging measurements. Procedures used to implement this, such as inversion through Markov Chain Monte Carlo sampling, are typically computationally intensive, but the full uncertainty in the results is captured.
The subject of this presentation is an alternative Bayesian method in which all relevant uncertainties in formation properties, and their importance for the result of the evaluation, are defined at the outset and used to generate a large set of synthetic formations together with the responses of various logging tools to these synthetic formations. This synthetic data can be used to generate histograms and cross-plots to validate that the uncertainties defined at the outset have been correctly incorporated. The data set is then reduced, or “pruned” by using the results of available logging measurements, together with prescribed uncertainties in these measurements. The Bayesian inference is thus reduced to a filtering operation using measured tool data to select elements from a large data set with all relevant and possible combinations of formation properties and associated logging tool responses.
Biographical Details of the Speaker
Mirano Spalburg is retired. He enjoyed working for Shell as a petrophysics assurer, a studies and operational petrophysicist and as a researcher over a 30+ years period. He has a PhD in Mathematics and Physics and an almost lifelong affection for Bayesian methods.
The Norwegian Cuttings Digitisation Project – Application of Probability Pruning by Filtering in Petrophysics
In the new digital era where the quest for Big Data has become paramount, the Norwegian oil industry and academic community has decided to spearhead the approach to Machine Learning challenges.
This DPS short talk will present the Norwegian Released Wells cuttings digitalization project and be mainly focused on the objectives, advantages and limitations related to this specific program.
This is a bold initiative in a collective research and development effort to create one unbiased database to train and develop specific artificial neural networks and algorithms.
Will the controversial cooperation between human and artificial intelligence be a success in the future scientific re-evolution…? I guess we will all see as the near future, for now, is still uncertain.
Prof. Quentin Fisher
School of Earth and Environment, University of Leeds, Leeds, LS2 9JT, UK
Large volumes of gas remain trapped within tight gas sandstones (TGSs), which can be produced at commercial rates using modern drilling and completion technologies (i.e. horizontal wells and hydraulic fracturing). Characterizing is often regarded as difficult, time consuming and expensive. The Joint Industry Project, PETGAS, has been running for ten years and has the specific aim of improving the way that we characterize TGS’s. It is built a high quality database of key petrophysical properties that has been used to identify key controls on the petrophysical properties of TGSs and also provides analogues for reservoir when core analysis is not available. The analysis of the results has been aided by the development of a be-spoke data visualization and data mining software, PETMiner, that allows image data (e.g. SEM and optical micrographs, CT scans etc.) to be integrated with laboratory measurements (e.g. porosity, permeability, capillary pressure data etc.).
The project has developed new experimental techniques such as high pressure, stressed mercury injection porosimetry, which provide valuable insights into the capillary pressure of low permeability sandstones. A particularly exciting development, which is currently undergoing field trials, is that the estimate the likely flow properties of reservoirs based on the integration of the results of microstructural characteristics of cuttings with wireline log analysis. The analysis can be applied very rapidly (12 hours of receiving samples) and is particularly useful for reappraising tight reservoirs where no core was taken or for providing rapid estimates of properties before core is available.
The presentation will highlight some of the key advances made in the characterization of TGSs and will also discuss some of the key knowledge gaps that remain.
Prof. Fisher studied geology at Sheffield University after which he gained a PhD in geochemistry from the University of Leeds. Fisher then spent 15 years conducting research and consultancy on the impact of faults on fluid flow in petroleum reservoirs. In 2008, he took up the Chair in Petroleum Geoengineering at the University of Leeds where he has led research projects that integrate workflows and software in the geological, geophysical, geomechanical and petroleum engineering disciplines. His current research interests include: unconventional hydrocarbons; measurement, visualization and data-mining of petrophysical properties; faulting and fluid flow; coupled fluid flow-geomechanical modelling; multiphase flow in low permeability porous media.
UNDERSTANDING FUNDAMENTAL CONTROLS OF HYDROCARBON SATURATION: FROM STRESS CORRECTIONS TO PERCHED WATER CONTACTS (click for PDF)
Building realistic and reliable subsurface models requires detailed knowledge of both the rock and fluids involved. While the hydrocarbon volume estimation has a profound impact on the viability of a development, next to the permeability, saturation height models, free fluid levels and the hydraulic communication have a significant role in determining the recoverable reserves.
When in different parts of the same field different free fluid levels (leading to different fluid contacts for the same rock quality) are identified, the lateral hydraulic communication at the field level can be challenged. In this presentation, we propose a new strategy in studying one process leading to different free water levels (FWL) known as “perched” water contacts. Perched water contacts are the result of water entrapment (behind barriers for lateral flow) during hydrocarbon migration in the reservoir. The fundamental controls that lead to the perched contacts formation are studied and shown to be the rock quality and relative permeability. Counterintuitively, the perching effect is not going to feature in poor quality rocks (sub-milli Darcy permeability) – the effects would be visible only for a considerable barrier height. Regarding transition zones, the results show no significant difference is expected above the perched zone when compared to the unconstrained parts of the field. Field observations and dynamic simulations are used to identify the perching controls. A clear distinction is shown between capillary pressure and buoyancy. The fundamental assumption that the capillary pressure can be calculated by using the height above free water level is shown to be deficient when water becomes immobile.
Concerning the process of building a Saturation Height Model from core measurements, we use a recent methodology that aims at ensuring consistency between permeability and Saturation height. The MICP or Saturation height model carries an intrinsic permeability that can be compared to the permeability model. The results show a significant inconsistency can occur between the porosity -permeability data (a reliable, well controlled and measurable property under stress) on one hand and the MICP/SHM inferred permeability on the other. The conclusion is that the most robust dataset for preparing the SHM is under the conditions the MICPs/PCs have been acquired. When the MICPs/PCs have been acquired under ambient conditions and the resulting model has as inputs stressed porosity and permeability, the SHM will predict the correct stressed entry pressures. The findings are validated against a dataset where the capillary pressures acquired under both ambient and stress conditions.
Iulian N. Hulea is a Senior Petrophysicist working for Shell Gloal Solutions BV, Projects and Technology in the Nethelands, currently working on Global reservoir studies. Before this position he held a carbonate (field development planning) Petrophysicist and a Research Petrophysicist position (both in Shell). He holds a Master (Bucharest University, Romania) and a PhD (Leiden University, The Netherlands) in experimental physics. After completing the PhD (2004) he held a postdoctoral position at the Delft University of Technology, Kavli Institute for Nanoscience also in The Netherlands.
Cement Evaluation with LWD Sonic: methodology description and comparison to conventional cement evaluation. (click for PDF)
Historically, LWD Sonic has struggled to provide quantitative cement evaluation due to the interference between casing and LWD collar signals. However, recent developments in tool design provide significant attenuation to collar signals, lowering the interference effect and allowing the reliable use of casing signal to quantify cement bond. The methodology presented uses a summation model approach to analyze the attenuation of the casing and tool collar signal along an array of receivers from an LWD sonic tool, to extend the quantitative cement evaluation to the full range of bond index applicable in all types of casing and cements (Pistre et al., 2015). The results are compared to Wireline CBL to demonstrate the potential and limitations as an alternative to conventional cement evaluation.
Along-hole Depth Measurement And Reducing Uncertainty. (click for PDF)
Along-hole depth has remained a measurement disciple that most recognize as being important and necessary to get right. But it is invariably taken for granted, unless it is “wrong”. But few actually know what “right” means. And fewer understand where the responsibility for the success of the measurement lies. The along-hole depth presentation includes defining this responsibility, as well as a discussion of the measurement process, the correction methodology and the numerics, and how these can affect uncertainty of measurement results. The Way-point correction model will be explained, applicable to both wireline and drill pipe depth determination, and an example with be presented where the use of Driller’s Way-point Depth (patent applied) arrived at quantified uncertainty for drill pipe derived formation depths.
Gassmann equations (Gassmann, 1951) are used to calculate seismic velocity changes that result from variations in reservoir fluid saturation. These equations became predominant in the analysis of a direct hydrocarbon indication from seismic data through their use in analyzing the compressional to shear velocity ratio, Vp/Vs. This Vp/Vs ratio is used in many industry analyses, such as the amplitude variation with offset (AVO) analysis developed by Castagna et al. (1993). Multiple authors have since published a variety of Vp/Vs seismic interpretation techniques that use empirical relationships with Vp, Vs, and porosity terms. Unfortunately, however, there is a gap in the use of Vp/Vs relationships in petrophysical interpretation.
Recent years more and more complex wells have been drilled, quite often through depleted formations. NPT due to losses or stuck events can have significant impact on the project economics. Comprehensive geomechanical model can highlight potential hazards and allow to take early actions to mitigate issues.
Elasticity and particularly its anisotropy is a vital part of the comprehensive geomechanics model. As it will be shown, it has dramatic impact on the horizontal stresses profiles. Presentation demonstrates anisotropic elasticity modeling process.
The suggested workflow exploits Reuss, Upper and Lower Hashin-Shtrikman bounds for various cases of dispersed clay modeling. Each of the bounds corresponds to specific dispersed clay textures, like clay cementation, pore filling etc. These textures are classified and tied to the corresponding bounds.The rock anisotropy is modeled by Backus averaging of shaly sands with dispersed clay as a first component and laminated clay as a second component. The degree of anisotropy is controlled by the volume of laminated clay and its elastic moduli. The model is calibrated through several rock-physics cross-plots. The most optimal way is to calibrate model with measured velocities in vertical and horizontal wells. Other options like Stoneley wave driven horizontal shear velocity, calibration with core etc. and its pitfalls will be discussed as well. Typically, the strain response of the rock and the associated velocity changes is measured in pore depletion experiments. The velocity is determined by analyzing the first arrival of a transmitted ultrasonic wave. The relation between velocity changes and strain is generally well explored and understood. We propose a method for the monitoring of the deformation using the diffuse field, that is to say, focusing on the coda wave of the transmitted ultrasonic wave. Cross correlation analysis of the coda part returns higher order of information associated with inelastic changed in the medium. The applications are diverse and range from civil engineering, to seismology and reservoir monitoring.
Typically, the strain response of the rock and the associated velocity changes is measured in pore depletion experiments. The velocity is determined by analyzing the first arrival of a transmitted ultrasonic wave. The relation between velocity changes and strain is generally well explored and understood. We propose a method for the monitoring of the deformation using the diffuse field, that is to say, focusing on the coda wave of the transmitted ultrasonic wave. Cross correlation analysis of the coda part returns higher order of information associated with inelastic changed in the medium. The applications are diverse and range from civil engineering, to seismology and reservoir monitoring.
Dr. Aletta (Nikoletta) Filippidou is a geologist, turned geophysicist, turned petrophysicist, turned geomechanicist; she basically abuses rocks, that’s it. She did her MSc jointy in the University of Athens and NTNU in Trondheim, and then a PhD in Geophysics at TUDelft. During her PhD she designed, acquired, processed and interpreted 3D seismic experiments of a Jurassic siliciclastic sequence in Northern France and a Miocene carbonate prograding reef in Mallorca using high-resolution high-frequency portable seismic sources. Her PhD thesis was ultimately on multi-scale transmission measurements, focusing on scattering and attenuation of seismic waves. She works for Shell since 2006, and focused on carbonate reservoirs, mostly in the Middle East for 10 years. The last two years she works for the Earthquake Study Team for NAM largely as a research coordinator and project manager, but also squeezing some time for own research within the Rock and Fluids Lab at Shell and TUDelft.
Rock Physics Integration: from Petrophysics to Simulation
by Dr. Reza Saberi, CGG, The Netherlands
The science of rock physics creates a bridge between elastic properties (e.g. Vs/Vp, seismic, elastic moduli etc.) and reservoir (e.g. porosity, saturation, pressure etc.) and architecture (e.g. laminations, fractures etc.) properties. It also should allow for a reliable prediction and perturbation of seismic response with changes in reservoir conditions. An appropriate rock physics model should be consistent with the available well and core data, and surface and borehole seismic as well as production and reservoir engineering figures. This requires that rock physics act as an integrating tool between different disciplines. This talk review rock physics applications in different subsurface disciplines like Petrophysics, Geophysics, Geomechanics and Reservoir engineering.
Reza has been with CGG since 2011 and has more than 15 years of experience working in the oil and gas industry. He first started as a mining exploration engineer in Iran and then moved to the oil and gas industry as a geoscientist, geophysicist and rock physicist. He has been working with NIOC, Shell, Fugro-Robertson, Fugro-Jason and CGG in different roles in Iran, Norway and Netherlands. His most recent role is as Rock Physics Product Development Manager where he leads a team that develops different rock physics modules within the CGG GeoSoftware portfolio. He is also involved with different rock physics R&D projects in CGG and gives worldwide training on rock physics and its practical link with other subsurface disciplines. Reza holds a M.Sc. in Petroleum Geosciences, NTNU, Trondheim, Norway and a Ph.D. in Reservoir Geophysics and Rock Physics from the University of Bergen, Bergen, Norway.
Laboratory research efforts on geothermal engineering at TU Delft
by Richard Bakker, TU Delft, The Netherlands
Responding to an increased demand for clean, green, carbon-neutral energy, the Dutch ministry of economic affairs signed a “Green Deal”, aimed to extract geothermal heat at depths below 4000 m which brings with it some new geotechnical challenges. A number of examples of current laboratory research at TU Delft will be shown including a deep porous sandstone and fractured reservoirs. In addition, research on Radial Jet Drilling (RJD) is presented. This technique is likely to provide better control on enhanced flow paths in geothermal settings. It requires less fluids compared to conventional hydraulic stimulation techniques, thereby reducing the risk of induced seismicity .
Dr. Richard Bakker is an experimental rock mechanics specialist working at the TU Delft rock mechanics laboratory within the Geothermal Engineering group of Prof. David Bruhn. He works as a Post-doc within the EC funded Horizon2020 project ‘SURE’, which focusses on Radial Jet Drilling (see: http://www.sure-h2020.eu/). He did his MSc at Utrecht university in Geology and Geophysics and wrote a thesis about paleomagnetism and uplift rates of the island of Timor, SE Asia. His PhD was at ETH Zürich in the Structural Geology group, where he worked on the mechanical properties of rocks in volcanic settings using a high pressure and temperature deformation apparatus (Paterson apparatus, max 1200 ˚C, 500 MPa). His thesis focused primarily on basalts and carbonates found in the basement of Mt. Etna.
by Bart van Kempen, TNO, The Netherlands
Reservoir evaluation plays a major role in the exploration of geothermal reservoirs. The chance of success of a hydrocarbon prospect is dependent on the water saturation, while the most critical parameter in geothermal exploration is the transmissivity. In conventional reservoirs the net thickness is usually relatively easy to determine and the uncertainty will often be quite narrow. Reservoir permeability on the other side is one of the properties hardest to predict. Part of our work at TNO-AGE concerns calculating the expected geothermal power at various scales (national to local). As permeability and net reservoir thickness are the most critical factors in these calculations, we combine and compare all available data to improve estimates and reduce uncertainty. Multiple data sources and scales implies a certain complexity which will be highlighted and discussed in this presentation.
Bart has a background in geology, core analysis and petrophysics with well over 5 years experience. He is currently working for TNO-AGE, the advisory group for the Ministry of Economic Affairs and Climate (MEA) as cluster leader Geothermal energy. His technical work comprises geoscience work on geothermal related issues in support of compiling evaluation reports and advises to the MEA pertaining to: licence applications, financial support measures and policy support. His specialisation is, reservoir characterization of geothermal aquifers. Therefore, his work focuses on petrophysics, well testing interpretation and production evaluation.
by Gulfiia Ishmukhametova, NAM
After initial plug and abandonment activities in one reservoir, measurements showed pressure build up in the annuli. Spectral noise, high precision temperature and production logging were performed to determine the cause of sustained annulus pressure and the location of leaks. The data acquisition was performed both under shut-in and pressure bleed-off conditions and both log responses were compared to identify changes in noise patterns. The noise from specific events such as channeling or reservoir activity was detected, so the abandonment program could remediate these issues successfully.
Application of spectral noise logging in this field yielded evidence that this technology can identify annulus flow for very minor build-up rates (0.1 bar/day). Our work demonstrates the ability to locate the source behind multiple barriers and to validate plug integrity. It was observed that noise responses have a good correlation with ultrasonic cement evaluation logs aiding better understanding of the gas migration mechanism and change in noise patterns.
by Kamaljeet Singh – Schlumberger
Worldwide, government and regulatory officials are informing the oil & gas industry that unproductive wells must be sealed to permanently remove these potential environmental threats. Services companies are developing tools and methods to limit the economic impact of fulfilling these obligations. A crucial requirement of permanent abandonment procedure is the placement of a cement plug across the wellbore and in the annuli of remaining casing sections in the well once upper sections have been successfully cut and pulled out.
This presentation aims to demonstrate the use of a multi sensor wireline tool to characterize annular material based on acoustic impedance properties and flexural wave imaging. This data is used to confirm annular barrier, support casing cut and pull optimization and evaluate Perforate, Wash & Cement (PWC) P&A technique.
Value of Information – Data acquisition trends and learnings (click for PDF)
Abdul Hamid, EBN
Data acquisition is an essential part of the exploration and development phase of a project. Data has its highest value when obtained in the exploration phase of a project where the aim is to reduce uncertainties as much as possible. Due to the low oil price many exploration projects are cancelled or deferred. Those projects which are approved are challenged with keeping the costs as low as possible.
EBN is in the unique position to see the trends of data acquisition in the recent years and the value of the information taken from data acquisition. To emphasize these trends a data analysis is done on almost 20 exploration wells of the past 5 years. Since EBN is partner in almost all oil and gas wells in the Netherlands, it has a great overview of the logging strategies of the operators and their post-mortem challenges. Hence EBN is encouraging a basis set of logging measurements in exploration wells as a best practice for the Dutch Oil and Gas industry.
Value of information analysis impact on data acquisition programs
by Jean-Paul Koninx, Shell
In a time of lower oil prices and cost reductions, data acquisition programs are under pressure. They are an easy target for quick cost cutting. How to safeguard essential data acquisition? How to assess the value of it?
The answer lies in a structured Value of Information analysis. While there are a lot of misconceptions and myths around VOI analyses, the presenter will provide you with a simple and structured approach, that can be easily applied to many problems. This not only helps justify your data acquisition (if warranted!), but in fact brings out where the value is.
System Approach for Enhanced Pulsed-Neutron Applications
Jon Musselman (Weatherford)
Through-casing formation evaluation using pulsed-neutron measurements has advanced to address many challenging environments. Relatively low porosity, multiple casing strings, complex completion hardware, and the need for very accurate fluid saturation results are a few of many situations that pose challenges for traditional capture measurements with conventional pulsed-neutron tools. These challenges can be met using a systems approach. Advanced tool hardware and instrumentation forms the foundation of the logging system, but a combination of rigorous calibration, detailed response characterization, and powerful workflows and analysis techniques are required for accurate results.
The presentation reviews one such system, with emphasis on the response characterization and summary workflows derived from characterization. These can be applied to oil and gas reservoirs in a wide range of environments.
Extended Monitoring of a Mature Field – A Case Study
Hans de Koningh (Xodus Group)
A mature gas field changed ownership after 30 years of production. The field produces from multiple fault compartments, with varying gas – water contacts and depletion mechanisms. The new owner resumed field surveillance with a large campaign including several pulsed neutron log surveys. ON interpretation of the data it was found that many of the new surveys deviated significantly and consistently from original baseline surveys. An explanation was found to explain these deviations and justify a correction so that the entire set of pulsed neutron surveys could be interpreted consistently.
Joint Interpretation of Magnetic Resonance- and Resistivity-Based Fluid Volumetrics – A Framework for petrophysical evaluation
Holger Thern (presenter) and Geoffrey Page, Baker Hughes
The accurate quantification of fluid volumes is one of the most important tasks for determining the economic value of hydrocarbon reservoirs. Fluid saturation calculation from resistivity logging data has been established for many decades with known benefits and challenges. More recently, the nuclear magnetic resonance (NMR) logging technology has developed as an alternative, robust method for direct fluid volume estimation by separating movable from bound fluids. As today’s reservoirs are becoming more challenging, conventional resistivity logging data evaluation involves increasing difficulties and ambiguities, for instance in complex lithology due to the presence of conductive minerals, low formation water salinity, fractures and vugs, or local variations in water resistivity. NMR logging data processing and interpretation are also not straight-forward in complex carbonates and heavy oil reservoirs, as well as in case of wettability alteration and due to the presence of magnetic minerals. Ambiguities in either of the measurements can be efficaciously addressed by combining data from both logging services.
We present a systematic compilation and discussion of main properties affecting resistivity and NMR fluid volume estimations such as Archie parameters and T2 cutoffs. Several log examples illustrate a wide range of reservoir scenarios. In addition to the log interpretation aspect, we also relate the results to their applications ranging from real-time drilling optimization through hydrocarbon-in-place estimates and reservoir modeling input to production and completion decisions.
Forward Modelling of NMR Logs in a Chalk Reservoir
Wim Looyestijn (consultant)
It is well known that interpretation of NMR logs on the basis of core-derived parameters often fails because the down-hole situation is much different from that in the laboratory. Core measurements at full in-situ conditions are in principle possible, but very expensive and therefore bound to span a limited range of properties.
We demonstrate that the same can be achieved by forward modelling of the NMR response. Starting point is a representative set of water-saturated core samples measured at ambient conditions. Forward modelling then introduces changes in the NMR response corresponding to full in-situ conditions, including effects due to the presence of native hydrocarbons, mud filtrate invasion and wettability. Interpretation parameters, such as (variable) T2-cutoff, and permeability exponents can now be computed on NMR data as they appear on the log. Once the workflow has been set-up, any change in conditions is automatically translated in an update of the correlations; this would not be possible with laboratory experiments.
We show that the actual log response is faithfully predicted by our modelling for two wells in a N-Sea chalk reservoir.
This study was presented at the SPWLA symposium in Cartagena, 2012, and received a Best Paper award. Also published in Petrophysics Vol.54, No.2, April 2013.
Heterogeneous Carbonate Reservoirs: Ensuring Consistency of Subsurface Models by Maximizing the Use of Saturation Height Models and Dynamic Data
Iulian Hulea, Shell
Attempts to characterize carbonate reservoirs follow various rock-typing methods that focus on Special Core Analysis (SCAL) output where core-derived permeability and capillary pressures play a central role. Given the late stage in a project where these results typically become available, integration with dynamic measurements such as wireline formation testing and well testing data is often overlooked. Mobilities derived from formation testers can be compared to permeabilities obtained from various averaging methods. Where no core permeabilities are available, a permeability curve may be derived based on the capillary pressure data that is already part of the model.
Laboratory Test Methods for Determining Capillary Pressure Data
Albert Hebing – Laboratory Manager – PanTerra Geoconsultants
Core capillary pressure data provide fundamental input to reservoir models and saturation-height functions that in turn are necessary to calculate STOIIP and initialise reservoir simulation models. As SCAL data experiments are seen as the “ground truth” in formation evaluation, it is therefore important that the appropriate test method is selected, and correct data interpretation is done.
This DPS presentation is to give an overview of the various analytical techniques that are employed in the industry to obtain Pc lab data, and the advantages and limitations of each individual method.
“The evolution of life-cycle petrophysical evaluation and data acquisition techniques in NAM”
Oscar Kelder – NAM
Oscar will present a talk on how evaluation and data acquisition techniques in life-cycle petrophysics in NAM has evolved over the years, its current challenges and its direction in the future.
“Amstel field – from first oil discovery to first oil production”
Danijela Krizanic – Engie
Located 12km NW of Scheveningen beach, the field holds a title of the first oil discovery in the Dutch offshore. Although it has been discovered in 1962; it has not been put into production until early 2014.
The presentation will cover the progress of the field development since its discovery with focus on reservoir characterization aspect of the project.
– Holds MSc in Petroleum Geology from University of Zagreb, Faculty of Mining, Geology and Petroleum Engineering. She worked for INA Oil Company and Baker Hughes before joining Engie in 2009. Currently she works as asset Petrophysicist for Dutch offshore oil and gas fields.