"RhoVe Method - A New Empirical Pore Pressure Transform"

Matt Czerniak (GCS Solutions, Inc.)

Abstract:

A new empirical pore pressure transform has been developed using modifications to methods first proposed by Alberty and McLean, 2003, and Alberty, 2011.  The rhob-velocity-effective stress (Rho-V-e) method produces a model-driven, stand-alone set of “virtual” rock properties, which at intermediate positions are consistent with Bowers method default values for the Gulf of Mexico (Bowers, 1995, 2001).  The RhoVe method uses a single transform to convert both compressional sonic and bulk density to common estimates of effective stress and pore pressure where convergence of the two transformed properties offers a robust solution.

Velocity-density conversion functions (of the form proposed by Bowers, 2001, and Raymer, Hunt, and Gardner, 1980), are mathematically linked to a continuous series of velocity-depth normal compaction trend functions. The calculations are limited by bounding end-member curves that provide a basis for intermediate (fractional) solutions of velocity-effective stress and density-effective stress relationships that are applied to a well of interest.  

Paired velocity-depth compaction trends were iteratively solved by using published theoretical porosity trends for smectite and illite (Lahann and Swarbrick, 2011), and published velocity-depth normal compaction trends (Ebrom and Heppard, 2010).  By using the comparative velocity-density functions that match the offset well data in cross-plot, normal effective stress for each end-member and intermediate solutions can be calculated by integrating the discrete velocity-depth profile - now converted to density-depth. The method produces robust solutions as tested on multiple deep water Gulf of Mexico wells, and extends the predictability of high-velocity, low-effective stress rock types such as those found in the Deepwater Gulf of Mexico Wilcox-equivalent Paleogene and older section.  The velocity-effective stress trend curves can also improve pore pressure characterization of the overlying overburden section extending to the mud line.  Advantages of the RhoVe method are that it can be made interactive and fast, relative to the application of other acoustic transform methods. 

This talk attempts to build on previous efforts by other workers to include the role of clay type, clay volume and diagenesis on altering velocity-effective stress relationships and presents a technique in which the effects of clay diagenesis and other factors may be captured and utilized empirically for pore pressure analysis and prediction.

Biography:

Matthew Czerniak is the Director of GCS Solutions, Inc., The Woodlands, TX. He received his B.S. in Geology from Michigan State University and M.S. in Geology and Geophysics from Louisiana State University. He has worked as a professional geologist for 33 years, with about 20 years of work specializing in pore pressure analysis and prediction. He has worked for BP, Mobil Oil Exploration, Chevron, Hess, BHP and ConocoPhillips. 

"Recognizing Hydrodynamics for Reservoir Volumetrics, Field Development & Well Placement" 

Sam Green (Ikon Science)

By recognizing and quantifying the regional distribution of overpressure a better understanding of hydrocarbon distribution can be built. Changes in aquifer overpressure represent fluid potential driving hydrodynamic flow. When hydrocarbons are trapped above a dynamic aquifer the hydrocarbon-water contact becomes tilted; the magnitude of the tilt is controlled by the differences in overpressure and the relative fluid densities. Structural closure may no longer be the key control on fluid distribution which is now being controlled by the hydrodynamic spill point. If the distribution of hydrocarbons is no longer controlled by structure then the placement of exploration or appraisal wells requires careful consideration. If a fluid contact can be shown to tilt down to the West then a well drilled on the East will encounter a shallower contact, or possibly water if the tilt is significant, and the decision may be made to abandon a prospect. However, a well drilled on the West may have a deeper than expected contact leading to an interpretation of a significant discovery. Furthermore, if the fluid contact is tilted then the volumetrics of the trapped hydrocarbons changes, either positively or negatively, but must be assessed. In all cases the impact for future exploration, development and appraisal are important.

The Miocene reservoir system in the Gulf of Mexico has been shown to be laterally drained (Hauser et al, 2013), i.e., low overpressure reservoirs sandwiched between high overpressure shales in the K2 (Sanford et al, 2006) and Knotty Head (Williams et al, 2008) Fields. Systematic changes in reservoir overpressure have been identified in the location of the Mad Dog Field as well as a tilted hydrocarbon-water contact (Dias et al, 2009). The work presented here discusses the likely impact on hydrocarbon distribution for the Miocene reservoirs in more detail. Furthermore, the discussion will extend the understanding of the geological-pressure controls on fluid distribution to the Lower Tertiary Wilcox play and comment on the likely impact for that system. 

"Geological and Geomechanical Modeling of the Haynesville Shale: A Full Loop for Unconventional Fractured Reservoirs"

W. Sebastian Bayer, Marcus Wunderle, Ewerton Araujo (BHP Billiton)

Abstract:

The Haynesville Shale remains an extremely prolific shale gas-producing reservoir. The question is no longer how we produce gas from the Haynesville, but how we produce gas more efficiently. We have designed and implemented a multidisciplinary project to optimize completions and potentially increase productivity. Our detailed reservoir characterization takes into account hundreds of wells, thousands of quality data points, core studies, seismic interpretation, geologic, petrophysical, and geomechanical models. Understanding the matrix and fracture components of unconventional fractured reservoir systems is critical. In this case study, we attempt to demonstrate our methodology in the simplest form by looking at each component independently, with a geocellular reservoir model for the matrix (storage) and a discrete fracture network (DFN) for the natural fractures.

Biography:

Sebastian Bayer is a Senior Reservoir Geologist with more than 10 years of industry experience focused on integrated-fit-for-purpose reservoir modeling. He graduated from the University of Oklahoma with a MS degree in Structural Geology and Stratigraphy and with a BS in Geology from the Universidad Nacional de Colombia. His current interests focus on integrated reservoir characterization and implementation of discrete fracture networks (DFN) based on geologic scenarios for the matrix and fracture components of the system. Scenarios integrate subsurface data, differentiate Geomechanical units, and incorporate stress. His work is based on robust static parameters to evaluate reservoir quality and production performance.

Marcus Wunderle is a Geologist. He has 10 years of experience in the oil and gas industry spanning conventional development, unconventional exploration and development. Most recently he has been working on the Haynesville shale as a Geologist and Geomodeler. He is a graduate of Ohio University with an MS in geology, focusing on Geoscience Education, and a BS in Earth Science Education focusing on geology. His current work is primarily focused on interpreting and integrating all subsurface data into regional to well-scale geomodels for reservoir characterization.

Ewerton Araujo is the leader of a team of geomechanics experts at BHP Billiton. With 15 years of experience in the petroleum industry he has applied geomechanics across the entire life cycle of oil and gas fields. He holds a PhD and Master’s degrees in Geomechanics from the Pontificia Universidade Catolica do Rio de Janeiro, and a BS in Civil Engineering from Universidade Federal da Paraiba in Brazil. Currently, he is leading the implementation of cutting edge geomechanics technology within BHP Billiton with the application of sophisticated Finite Element Method simulations by making the bridge between Geological and Reservoir Simulation models for both conventional and unconventional assets of the company.

"Dipole Shear Anisotropy Using Logging While Drilling Tools"

Matthew Blyth (Schlumberger)

Abstract:

This paper describes new modeling capabilities and processing workflows to output dipole shear anisotropy answers, such as the fast and slow dipole shear slownesses and azimuths from LWD sonic tools. A major objective is to model the coupling between the drill-collar and formation flexural modes that has been the root cause of measurement problems with LWD dipole in the past and invert either of these two modes for the formation dipole-shear slowness. A new dispersion extraction algorithm isolates and identifies both of these dispersive arrivals in the recorded wave train. This is followed by a model based inversion of either the drill-collar flexural or formation flexural dispersions to obtain the dipole shear slownesses either in a fast or slow formations. The method offers a robust and reliable dipole shear answer and opens the door to formation anisotropy characterization in all formations with LWD. 

Biography: 

Matthew Blyth is the LWD Geophysics, Acoustics and Geomechanics Domain Head with Schlumberger Drilling and Measurements.   Since joining Schlumberger in 1997 he has filled a variety of roles, all within the field of logging while drilling. He is currently involved in the long term technical development plan for LWD acoustic and seismic technology and their applications within Schlumberger.  He has authored and coauthored multiple papers on LWD technology and its uses.  Matthew graduated in 1996 from Cambridge University with a Bachelors and a Masters in Engineering. He is a member of the SPWLA, SPE, SEG and ASA and has served as both a VP and as President of the Houston SPWLA chapter.  He is currently the secretary of the SPWLA Sonic SIG and is a 2016/2017 SPWLA Distinguished Speaker.

"Practical Seismic Petrophysics: The Effective Use of Log Data For Seismic Analysis"

Tad Smith (Apache)

The conditioning and analysis of log data for quantitative seismic interpretation is often simply categorized as “rock physics.”  Unfortunately, rock physics workflows often overlook or oversimplify the proper editing and interpretation of log data, the result of which can be unrealistic expectations and interpretations of seismic amplitude responses.  The more encompassing phrase “seismic petrophysics” better describes the necessary linkage between petrophysics and rock physics.  Seismic petrophysics not only includes rock physics, but also includes the proper conditioning and interpretation of log data that should occur prior to the application of rock physics and seismic models.  This is especially true in conditioning log data for shear-wave velocity estimation, fluid substitution calculations, and AVO modeling.  

This talk will focus on the important role of “seismic petrophysics” in the quest to extract additional information from subtle seismic responses.  Topics covered will include various aspects of log editing, petrophysical interpretation (including integration of other data sources- core, fluids, pressures, etc.), and some common pitfalls associated with the “workhorses” of rock physics (invasion corrections, shear velocity estimation, and elements of fluid substitution).   It is important to recognize that log data should not simply be recomputed to fit prior expectations as defined by a rock physics model.  Instead, rock physics models should be used as templates, which allow the interpreter to better understand the underlying physics of observed log responses and how they are governed by local petrophysical properties. Case studies will be used to reinforce critical concepts.

"Fully Coupled Geomechanics and Flow Simulation for Time-Lapse Seismic"

Jorg Herwanger (MP Geomechanics)

Time-lapse seismic is now an established technology for areal reservoir monitoring. The future promises an even tighter integration between seismic reservoir monitoring and simulation models describing the flow and geomechanical processes during reservoir production. 

To this end, the SEG under its SEAM consortium, conducted a pilot study to test the ability to accurately simulate reservoir production and reservoir geomechanics, use these simulations to predict velocity changes, simulate full waveform synthetics and create migrated images of these data. 

In this technical breakfast, we share the reservoir flow and geomechanical simulations, as well as the rock-physics modeling. 

The simulator is based on finite-element technology. This allows to employ an innovative meshing algorithm that retains the geometry of individual turbidite fans. The simulations clearly demonstrate different reservoir production processes, such as gas-out-of-solution, different speeds of pressure and fluid fronts, as well as reservoir compaction (due to pressure decrease) and dilation (around injectors).

"Enhancing Confidence in Fracture Prediction Using Advanced Seismic Data Analysis. A case study from Russia"

Konstantin Smirnov

Information on the areas of high fracture can play a key role in the successful development of the majority of carbonate and unconventional reservoir types. Seismic data are one of the sources of such information and with modern acquisition methods optimally designed to obtain the field data of the highest quality, the possibilities now exist to extract maximum information and knowledge related directly to fracture characterization. 

Conventional surface seismic methods for fracture detection rely on the measurement of azimuthal anisotropy, coherency analysis other attributes. Diffraction imaging has gained interest to fracture detection and it is based on the fact that diffraction is the direct seismic wavefield response to small scale subsurface discontinuities. Seismic diffraction can help to detect and map systems of subsurface discontinuities that could be related to faults or fracture corridors. Increasing the confidence in fracture prediction can also be enhanced further by combining (fusion imaging) of the diffraction energy volume, the azimuthal anisotropy intensity volume and the geometry (coherence or dips or curvature) volume together using RGB blending in the 3-dimensional space. The integration with well log data can be used to quantify the probability of the areas of high fracture.

These techniques are presented in an integrated fracture zones detection case study for the oil and gas province of Russia. 

"Dispersion and attenuation of seismic waves in fractured reservoirs" 

Boris Gurevich (Curtin University)

The detection and characterization of domains of intersecting fractures are important goals in several disciplines of current interest, including exploration and production of unconventional reservoirs, nuclear waste storage, CO2 sequestration, and groundwater hydrology, among others. The objective of this study is to quantify the effects of fracture intersections on the frequency-dependent elastic properties of fluid-saturated porous and fractured rocks. Three characteristic frequency regimes for fluid pressure communication are identified. In the low frequency limit, fractures are in full pressure communication with the embedding porous matrix and with other fractures. Conversely, in the high frequency limit, fractures are hydraulically isolated from the matrix and from other fractures. At intermediate frequencies, fractures are hydraulically isolated from the matrix porosity, but can be in hydraulic communication with each other, depending on whether fracture sets are intersecting. The theoretical predictions for each regime show good agreement with corresponding numerical simulations. The theoretical results are applicable not only to 2D but also to 3D fracture.

Overpressured formations have been encountered in every continent in the world where exploration wells are drilled for hydrocarbons. Unexpected overpressure is a major cause of drilling hazards like stuck pipe, well kicks, lost wells and blow-outs, that cost the industry millions of dollars. Accurate Pore Pressure Prediction (PPP) plays an important role in reducing drilling risk and cost, improving wellbore stability and optimizing casing seat selection and mud programs.
 
Paradigm provides technologies for well log and seismic-based Pore Pressure Prediction. Geolog Pore Pressure Prediction contains a rich collection of methods and formulas for pressure estimation using a variety of well logs. With Geolog Pore Pressure Prediction, the user not only predicts pressures at selected well locations, but also creates a 1D model for 3D seismic based Pore Pressure Prediction.
 
QSI Pore Pressure Prediction provides technologies for seismic based Pore Pressure Prediction, including:

• High-resolution velocity analysis
• Geologically plausible interval velocity creation
• Time-to-depth conversion of interpretation data and seismic data
• Pressure volume generation
• Pressure volume visualization and interpretation

In this technical session we shall present and demonstrate technologies and workflows using seismic velocity, with a focus on the following topics:

• Pore Pressure Prediction technology overview
• Velocity modeling for the purpose of Pore Pressure Prediction
• 1D pressure model development
• 3D pressure volume generation, visualization and interpretation

"Using digital rocks and pore-scale multi-physics to characterize a sandstone reservoir" 

Mita Sengupta, Hess Corporation

ABSTRACT

Digital rocks are 3D image-based representations of pore-scale geometries that live in virtual laboratories. Imaging techniques such as computed tomography (CT), microcomputed tomography (micro-CT), and FIB-SEM (Focused Ion Beam-Scanning Electron Microscopy) can help obtain 3-D high- resolution images of rock samples. These volume-imaging techniques produce data that can be explored using image processing and multi-physics simulations to understand material phases, grain structure, porous networks, and physical mechanisms that occur in them, without having to carry out destructive tests.

Today, we can use digital rocks to complement and expand physical measurements, and gain further insight into the key geologic properties that influence the physical behavior of rocks. We demonstrate the practical applicability of digital rock physics for reservoir characterization, particularly when integrated with physical measurements. In our study, we focus on porosity, permeability, electrical conductivity, and velocity measurements. Physical measurements provide “ground truth” to validate the digital computations. We combine lab measurements with numerical computations to enhance our understanding of multi-physics relationships in a heterogeneous sandstone reservoir. 

Digital rock physics is a powerful technique for understanding subsurface processes, and represents a paradigm shift in the field of rock physics. Our study shows that digital rock physics has evolved into a practically usable tool that can, not only bring physical insight into relationships between relevant rock properties, but can also bring quantitative value to real geophysical and engineering problems of oil exploration and production. Digital rock physics re-emphasizes the importance of rock physics as a strategic area of knowledge that builds and strengthens bridges between geology, geophysics and reservoir engineering.

"Statistical Rock Physics in Seismic Reservoir Characterization" 

Sagar Ronghe, DownUnder GeoSoluctions

ABSTRACT

This presentation will demonstrate the concepts and practical application of statistical rock physics in seismic reservoir characterization using data examples from the Carnarvon Basin, offshore Western Australia.

Quantitative, calibrated reservoir characterization integrates wireline and seismic data. Apart from the obvious resolution differences a number of issues affect the integration: wells may be few in number and preferentially located so that formation sampling is biased. Particular lithologies / fluids may only be intersected over certain narrow depth ranges. Recorded data by itself provides little understanding of the rock vertically and laterally away from the logged intervals. Wireline data, used in deterministic interpretation, provide a single solution without estimates of associated uncertainty. Under-sampled formations mean that the recorded logs are not representative of the population behavior of the particular lithology or fluid type under consideration.

Statistical rock physics addresses these issues and forms the cornerstone for the integration of well and seismic data in reservoir characterization. The workflow is illustrated with reference to well data from offshore Western Australia. Statistical rock physics comprises selecting and upscaling log intervals associated with particular lithologies, establishing depth dependent rock physics trends per lithology type, and stochastic modelling of the trends to generate probability density functions representative of the population behavior of key lithology and fluid combinations as a function of end member rock types, fluid content, reservoir quality and depth. 

Seismic reservoir characterization needs to be fit for purpose, given project objectives and data availability. Reservoir characterization methodologies span qualitative attribute analysis, deterministic inversion, probabilistic lithology predictions and stochastic inversion. Statistical rock physics provides the calibration between formation properties and the seismic response for all reservoir characterization techniques. Statistical rock physics models formation behavior in terms of both absolute rock property variation and amplitude variation with angle (AVA).  This presentation will show, using multiple data sets and results from published case studies, how statistical rock physics can be used to characterize expected seismic responses, ascertain whether lithologies of interest can be discriminated from a rock physics standpoint, provide AVA constraints to guide seismic inversion, derive probabilistic interpretations of lithology and fluid distributions from seismic attributes / inversion outputs, and quantify their petrophysical properties along with associated prediction uncertainties. 

"Big Bend Gulf Of Mexico Success, from Prospect to Production through Geoscience Integration"

Owen Stephens, Noble Energy

Big Bend is one of several recent discoveries made in Mississippi Canyon by Noble Energy and partners. Oil is contained in Lower Middle Miocene deepwater sandstones within a very high-relief combination structural/stratigraphic trap. This presentation will recount the subsurface analysis that drove the successful discovery and subsequent rapid development of the Big Bend Field.

Several techniques were used to de-risk Big Bend prior to drilling: Proprietarily processed WAz data provided meaningful uplift to the imaging adjacent and under salt, the DHI interpretation and migration velocities. This uplift increased the confidence in reservoir presence and quality. An improved velocity volume was used in the pore pressure analysis to assess column height and top seal potential, which helped mitigate containment risk. Chimney cube technology results confirmed migration pathway and thermogenic charge assumptions, as well as the leaky trap prediction from pore pressure analysis. Seismic inversion reduced concerns about reservoir and hydrocarbon presence. With the resulting increased confidence, the well drilled in late 2012,
discovering 130ft of high quality net oil pay.

After discovery, actively addressing the remaining field uncertainties allowed acceleration of both project sanction and first oil. Risk of the interpreted oil/water contact being a paleo-contact was reduced through fluid substitution modeling and geostatistical seismic inversion. An updated depositional model was created using sidewall core, conventional core from nearby analogs, image log analysis and seismic interpretation, reducing reservoir uncertainties and feeding into the reservoir model. This then guided a multi-phased reservoir modeling approach. First, a simple model provided production profiles for early project planning. Multiple deterministic cases were then used to assess volumetric and compartmentalization uncertainties. With those uncertainties understood, the development could be sanctioned as a single-well subsea tie-back, maximizing value by minimizing both appraisal costs and project costs, and accelerating first oil. The resulting early production history will allow further appraisal of field volumes and compartmentalization, in the upside case potentially justifying an additional producer and water injection.

Big Bend commenced production on October 26, 2015, less than three years from discovery and within the sanctioned budget, with production reaching over 20 Mboe/d.