2017 Spring Workshop

Integration, An Opportunity for Petrophysics to Generate Value

Richard Rosen (Richard L. Rosen Consulting)

Petrophysics, as Archie thought about it, is the science of understanding the physical properties of rocks. As such, it uniquely impacts the practices of all of the petroleum and geoscience disciplines. Each disciplines’ work can be thought of as a set of assumptions and facts about the response of rocks to the various exploration and development efforts. Value is therefore generated by the creation of knowledge and its reduction in uncertainty. From a risk discount point of view, reduction of risk generates cash.

Integration, in this process, requires petrophysics to understand the nature of these assumptions and to divine methods to turn these assumptions into facts.  The priority of these tasks depends solely upon how they influence actions among management in regards to the “So What?” and “Now What?” questions which drive the business. The quixotic pursuit in these endeavors requires a paradigm shift from technology is a cost to technology is an investment. There is a profound difference between the two philosophies in that costs are evil and must be destroyed and the expectation of returns on an investment.

Biography

Richard Rosen is retired from Shell Oil where he practiced petrophysics for 30 years. He has held positions in research and operations and for a time was responsible for the Petrophysical Sciences Lab tasked with the sacred responsibility of conducting the experiments that Archie, Waxman and Thomas, Purcell, Swanson, and many other Shell scientists first developed. He has given this speech, in one form or another, for many years begging for money. He now lives and consults in Denver.

Pulsed Neutron Logging and Formation Evaluation in Unconventional Reservoirs: Case Studies

Jorge Gonzales Iglesias (Schlumberger)

With the ever-increasing pressure to become more efficient in the oil and gas industry, from spud to completion of a well, acquiring measurements for describing reservoir properties in unconventional reservoirs have become an anomaly. Geoscientist teams are often left frustrated with limited data, such as gamma-ray (GR) and even drilling events, to populate their reservoir models.

From a formation evaluation (FE) stand point, the preferred method to acquire reservoir measurements is in open-hole (OH) conditions. This option is generally perceived as costly due mainly to the rig time required for the logging job and to a certain extent, the operational risks involved. It is then when the alternative of cased-hole (CH) logging becomes attractive since the previous factors are eliminated.

Cased-hole formation evaluation has been around since the 1950’s when GR and a neutron logs were used in conjunction to attempt evaluation through casing. Resistivity logs through casing were also emulated with the introduction of Sigma (S) and Carbon/Oxygen (CO) measurements in 1960’s and 1970’s respectively. The complexity of today’s reservoirs makes the use of these measurements (GR, Neutron and S) still insufficient to produce a reliable FE for unconventional reservoirs.

It was not until late 1970s, early 1980s that pulsed neutron log tools (PNL) started to introduce spectroscopy information that would allow to quantify the various minerals of the formation for either OH or CH environments. Early tools provided limited accuracy and precision as well as complex acquisition programs with extremely low logging speeds and a large number of logging passes that required intensive data manipulation and processing. It is perhaps both; the time consumed for the logging job and the time required to provide an interpretation that have hindered the PNL cased-hole alternative from being a more widely used option in FE by the industry to date.

Fortunately, technology has hugely evolved since early introduction of PNL tools and today slim PNL tools offer the possibility of acquiring such measurements mentioned earlier at much more faster speeds. Remarkable improvements in accuracy and precision as well as in computing software performances, allow a log analyst to turn around reliable interpretations in time with well schedules.

This paper summarizes the latest advancements of a slim PNL tool that can acquire simultaneously, sigma, neutron and the measurement of a new formation property known as the fast neutron cross section (FNXS) along with spectroscopy data for lithology information. The tool logged in this mode, combines time- and energy-domain spectral in a single mode at speeds up to 1000 feet per hour that makes a logging job much more attractive and operationally appealing. A series of case studies are shown to demonstrate the elevated specification of this new technology with a variety of applications from unconventional reservoirs to enhanced oil recovery.

Biography

Jorge Gonzalez is a Senior Petrophysicist currently working in the in the Permian Basin (Midland, US) as a Petrophysicist Domain Champion for Schlumberger Formation Evaluation with focus in Conventional and Unconventional Resources. Jorge has been with Schlumberger for 10 years starting as a Wireline Field Engineer for a short period and then as a Log Analyst in the North Sea Data Services Center. After 4 years as a Log Analyst in the North Sea, Jorge moved to the Permian Basin in Midland as a Petrophysics Associate Domain for 2 years where he began focusing on the petrophysical analysis of shale reservoirs. After this period ,Jorge took the role of Petrophysicist Domain Champion for the Permain Basin which is his current role. Jorge has received an MSc degree in Mining Engineer from the Universidad Politecnica in Madrid.

Effective Core Description, Interpretation and Data Capture Workflows in Mudrocks (or any rocks, really)

Katie Joe McDonough (KJM Consulting)

Goals and focus of core description and interpretation efforts may vary, and ideally should be established at the outset of any project.  Despite relatively easy subsurface correlations in many unconventional plays, the problem of understanding vertical and lateral reservoir property distribution persists. Carefully targeted, captured and calibrated rock data can determine the correspondence between depositional facies, stratigraphic stacking and reservoir characteristics such as porosity, permeability and brittleness. This information placed in stratigraphic context can then facilitate lateral prediction of reservoir properties away from the borehole (because… Walther’s Law!    "Vertical=Lateral.").

Any core description workflow must begin by establishing a Level of Detail appropriate to achieve the objectives of the project. These objectives should be client-customized, goal-oriented and designed to answer specific questions formulated at the outset. Ideally, detailed observation and facies delineation is then constrained by this project design and its implicit Level of Detail. Sedimentologic facies characteristics are then defined conventionally according to lithology, sedimentary structures, bedding types and fabric as well as ichnofabrics and trace fossil information. Details matter, but only if understood in context of the larger scale. Keeping LOD context requires designing the workflow so that larger scale ‘views’ are available and accessible during the course of observation and data collection. Using best practices, facies and sedimentologic data should be captured quantitatively and digitally using tools available. This allows immediate comparison and integration with wireline logs, petrophysics and seismic data.

Following (and during) sedimentologic facies characterization, ideal workflows incorporate facies trend interpretation to delineate stratigraphic stacking. This critical step allows up- and down-scaling to basin or reservoir scale, and represents an often-overlooked integration/interpretation step which greatly enhances utility of rock data. Once stratigraphic stacking is delineated, the hierarchical interpretation can be applied to understand petrophysical crossplot relationships to depositional facies as well as facies fabric relationships to mechanical stratigraphy. This leads to improved understanding of the controls and predictability of reservoir occurrence, distribution and performance.

Examples of tailored description/interpretation workflows and approaches applied to the following geologic intervals will be discussed:

Data Capture: Sedimentologically-defined facies, cycles and stratigraphy

• Cretaceous Niobrara
• Eocene-Oligocene Mudrock
• Cretaceous Marias River Shale
• Devonian Bakken Shale (Basin margin facies) * inclusion TBD
• Permian Wolfcamp (an e.g. of missing, sorely needed type of data)

Data Capture: Fractures

• Fracture type/orientation/intensity
• Mechanical stratigraphy
• T.Bratton CSM work on facies fabrics and fractures... * inclusion TBD

With Special Acknowledgements to Marshall Deacon, Lise Brinton, Robert Lieber, Brian Coven

Biography

Katie-Joe McDonough is a geological/geophysical consultant specializing in sequence stratigraphic and seismic interpretation. Her areas of expertise in sedimentology and depositional systems form the foundation of her work in stratigraphic basin analysis, exploration play assessment and reservoir-scale development. Dr. McDonough has worked continental to deep marine strata in conventional and unconventional plays in North and South America, East/West Africa, Europe, Indonesia and the Arctic. Dr. McDonough has over 25 years of diverse international and domestic U.S. experience in the petroleum industry including staff, consulting and advisory positions with Exxon USA, Mobil, Elf Aquitaine, EcoPetrol, Cimarex Energy, MedcoEnergi, Noble Energy, Anschutz Exploration, Enerplus , PDC Energy and ION Geophysical. She is an active member of AAPG (2015 & 2001 Annual Conference Technical Committee), DIPS, DGS, RMAG, SEPM-RMS and SEG. Dr. McDonough has also served as adjunct faculty teaching stratigraphy at Colorado School of Mines, and currently serves as an industry mentor in RMAG and CSM programs.

Assessing shales from well logs: a calibrated workflow with examples from the Bakken

Sue Cluff and Stefani Brakenhoff (The Discovery Group)

The Discovery Group has developed a standard workflow used to calculate total organic carbon (TOC), lithology, grain density, TOC-corrected porosity and water saturation, that is useful in most shale reservoirs.  The model requires a standard triple-combo log suite and shale-analyzed core data to calibrate the model.   This method has been successfully applied to basins both domestically and internationally.

We will show how to develop shale models using a deterministic work flow with an example from the Bakken shales of North Dakota; beginning with data collection practices, stepping through all of the processes needed for developing shale-corrected models, and applying these models to a database environment used to create valuable characterization maps and statistics of the shales.

Biography

One of the co-founders of the Discovery Group, Sue has over 35 years’ experience in the petroleum industry as a geologist and a petrophysicist. She is particularly interested in the integration of geologic, petrophysical, and engineering data into a coherent reservoir model. She has done a number of integrated reservoir characterization and field studies of tight gas sands of the Washakie, Green River, Wind River, Piceance, and Uinta Basins as well as in East Texas. She has also participated in a number of resource studies of various shale plays in the US. Previously, she was a part of international studies in Guatemala, Mexico, Argentina, Bolivia, Saudi Arabia, Indonesia, and Denmark.

Sue received a B.S. in Mathematics from the University of Illinois (high honors) in 1973 and M.S. in Geology at the University of Wisconsin at Madison in 1976. She began her career at the Chevron Oil Field Research Company in a technical service group which integrated core analysis and wireline interpretation into ongoing development and exploration projects, both domestic and international. She was transferred into the Chevron USA Rocky Mountains division where she worked as a development geologist in the Thrust Belt and western Colorado. In 1981 she joined Buckhorn Petroleum (later named Harper Oil and Midcon Exploration) as an exploration geologist in the Rocky Mountain District. Sue consulted for several years before co-founding the Discovery Group.

Biography

Stefani has over 13 years of experience in the petroleum industry. She graduated from the Colorado School of Mines in December 2002 with a B.S. in Chemical Engineering and a B.S. in Mathematical and Computer Sciences and a minor in Public Affairs for Engineers. After school, she was employed with Schlumberger for two and a half years beginning in 2003 as a Senior Open-hole Wireline Field Engineer in the Washakie and Greater Green River Basins of Southwestern Wyoming.

Stefani has been with Discovery Group for 11 years and is now a Sr. Petrophysical Engineer with specialties including log data cleanup, log normalization, reservoir characterization, log database setup and management, neural net solutions, tool theory and characterizations, water storage projects, and setting up and coding petrophysical workflows for tight gas and gas/oil shales. She has worked most on-shore basins in the U.S. as well as basins in Western Africa, Australia, India, Poland, Russia, the U.K., and U.A.E.

She is a member of AAPG, RMAG, SPE, SPWLA and DWLS. She has served a two-year term on the SPWLA board as a Regional Director and has held many roles in DWLS including Treasurer, President and currently inventories and mails all the on-line extra course material orders.

Extension of the Gameboard Approach for Facies-based Petrophysical Model Development

Margaret Lessenger (Rimrock Petrophysics) and Samuel Fluckiger (SM Energy)

Petrophysicists develop petrophysical models using common petrophysical software packages. These packages facilitate development of models calibrated to specific zones defined either by geological formation tops or depths within a well. Well logs respond to the physical properties of the rocks near the wellbore. These physical properties are grouped into distinct rock and log facies. Commonly, multiple different facies occur within defined zones, complicating zonal petrophysical models. Because well logs respond to facies within zones, facies-based petrophysical models are a significant improvement from zonal petrophysical models.

In this paper we present a workflow for developing facies-based petrophysical models for porosity and saturation. This workflow is an extension of the “gameboard” approach (Krygowski and Cluff, 2015). Using the gameboard approach a petrophysicist can quickly try multiple scenarios to find the parameters that honor all the data. We have built a gameboard in Spotfire (©TIBCO), a data visualization and analytical software package. Using visualization and analytical software we utilize categorical data (e.g., log and core facies, drilling fluid type), and quick data visualizations including map-based visualizations to calibrate petrophysical models.

We applied this workflow to the Upper Cretaceous Wall Creek member of the Frontier Formation in the Powder River Basin, USA. Core, log, and seismic facies have been defined in these reservoirs (Fluckiger, et al., 2015). Multiple log facies occur within sequence-stratigraphic zones, and there are lateral facies changes within zones. We demonstrate the workflow for developing improved petrophysical model parameters that vary with log facies within stratigraphic zones.

Biography

Margaret Lessenger is a consulting petrophysicist at Rimrock Petrophysics and Analytics in Denver with over 30 years of experience as a geophysicist, geologist and petrophysicist working in various basins in the Rockies, Appalachian Basin, North Sea and Gulf of Mexico. She has worked for the Superior Oil Company, ARCO Oil and Gas, Platte River Associates, the Colorado School of Mines Department of Geology, Williams Exploration, and Newfield Exploration. Lessenger holds a BS in Geophysical Engineering, MS in Geophysics, and PhD in Geology from the Colorado School of Mines. She is a member of SPWLA, AAPG, SPE and SCA.

Biography

Samuel Fluckiger received his B.S. degree in geology from Utah State University in 2000, and his M.S. degree in geophysics from the University of Utah in 2008. Before joining SM Energy in 2013, he worked for twelve years with Schlumberger Oilfield services in several different capacities ranging from Wireline Field Engineer, Research Scientist, Interpretation & Development Petrophysicist to finally Managing a team of Petrophysicists focusing on core-log integration. Samuel is now a Chief Petrophysicist at SM Energy primarily focused on advising various asset teams on the development of comprehensive reservoir models through the integration of core, log and seismic data.

NMR Applications in Unconventional Reservoirs

Dick Merkel (Denver Petrophysics)

The NMR measurement relies on signal from hydrogen not chemically tied to the rock matrix. That makes this measurement similar but yet different that the neutron porosity log which will, for instance, measure the chemically bound water (hydrogen) in gypsum. Most unconventional reservoirs have much lower hydrogen ion concentration in the fluid component (hence lower signal) than is found in conventional reservoirs. As a result, different acquisition, processing, and interpretation techniques are required to be applied in unconventional reservoirs.

This presentation examines the NMR log acquisition of T1 and T2 data and their interpretation for gas, oil, and water content. Major breakthroughs in NMR analysis is occurring in core measurements where higher frequencies can be used to look at shorter T1 and T2 times. This allows for the analysis and delineation  of kerogen, bitumen, fracture content, and compressibility as a function of pore size. Examples show how the high frequency core data can be used in combination with log NMR data for reservoir interpretation.

Biography

Dick Merkel is President of Denver Petrophysics LLC, which is a consulting firm dedicated to developing logging analytical techniques for petrophysical models tied to core, completion, and production data in complex reservoirs. Previously, he worked at Newfield Exploration Company where he worked on teams that developed reservoir models for unconventional oil and gas reservoirs in the Rocky Mountains. Prior to its closing in 2000, he was a Senior Technical Consultant at Marathon Oil Company’s Petroleum Technology Center in Littleton, CO where he worked for 13 years on evaluating new logging tools and technology, and developing techniques for their application in Marathon’s reservoirs. Dick holds a BS in physics from St. Lawrence University and a MS and Ph.D. in geophysics from Penn State. He is a past president of SPWLA, the SPWLA Foundation, and DWLS, and is currently a member of SPWLA, SPE, and SCA.

Enhanced Oil Recovery in Unconventional Formations: Gas Cycling

Derek Beckett (Core Laboratories)

Solving the problems involved in improving recovery from 5% OOIP to better than 20 – 30% OOIP using gas cycling and a look at the development and application of miscible gas injection to unconventional reservoirs. Evaluation of the cycle gas and reservoir fluid properties including swelling, minimum miscibility and multi contact revaporization is discussed. We then introduce the phenomena of bubble point, minimum miscibility pressure and interfacial tension deviation in nanopores from bulk (PVT) properties. Finally we examine the laboratory evaluation of gas cycling evaluation in the laboratory using representative core samples.

Biography

Derek Beckett is Director of Technology Development for the Petroleum Services Division of Core Laboratories. Derek has 40 years of international and domestic experience in phase behavior, core analysis and laboratory equipment design and construction.  Recent projects include the startup of Core Lab’s Digital Rock Characterization (DRC) group from feasibility study through hardware selection and the development of analytical protocols and the design and construction of a 3-phase, 20K psi pore pressure re-circulation rig. Current efforts are focused on understanding and increasing recovery in unconventional reservoirs using gas cycling methods.

Using Horizontal Borehole Image Logs and Geomechanics to Enhance the Design of Hydraulic Stimulations

Roger Reinmiller (Borehole Image Specialists)

This presentation is a case study illustrating the integration of borehole image log and geomechanical data to improve stimulation results. The case study involves a vertical pilot well with a full suite of open hole logs and three horizontal wellbores with borehole images. A geomechanical analysis augmented by mineralogy determination was performed on the pilot hole. The three horizontal image logs reveal substantial variation in the distribution of natural and drilling-induced fractures and faults along the laterals. The presence or absence of drilling-induced transverse and longitudinal fractures can be directly linked to the changes in frac gradient and proppant placement during fracture treatments. Applying the vertical well geomechanical study to the layers penetrated by the laterals, the geometry of the critically-stressed fractures and faults were determined for each horizontal well. Variation in differential stress along each lateral and changes in the geometry of critically-stressed fractures and faults significantly alters the induced hydraulic fracture response (complex vs. planar fractures) in these stages, ultimately governing production response.

Fracture gradient data, as they relate to drilling-induced and critically-stressed fractures, can determine the stage spacing and perforation clusters that should be used to optimize the fracture stage design, custom fitting the stimulation to lateral changes in stress anisotropy.

From production histories, we show that stage-by-stage modification of the pump-ins, accommodating image derived information, improved frac efficiency and EUR, even in highly fractured laterals.

Biography

Roger Reinmiller started Borehole Image Specialists in May of 2016 with several other colleagues. Prior to Borehole Image Specialists, Roger worked at Fronterra Geosciences for 10 years with an emphasis on the geological interpretation of borehole image logs, geomechanics, and incorporating these data to better understand hydraulic stimulation performance. Before working with Fronterra Geosciences, Roger worked at Baker Hughes, and all its prior entities, for 30 years in the wireline service side of the business. While working with Baker, Roger gained a thorough knowledge of open hole and cased hole services, operations and data interpretation. In his career, Roger has worked in all of the hydrocarbon basins of North America and has international experience in the Middle East and Central Europe.

Roger has a B.S. degree in Industrial Engineering from Northern Arizona University.

Pore Scale Imaging of Unconventional Reservoirs in Petrophysical Workflows

Terri Olson (Digital Rock Petrophysics)

Imaging technology has advanced in recent years to enable investigation of pore systems in very fine-grained reservoirs. A review of state-of-the-art techniques will include methods focused on nanometer- and micron-scale observations plus integration across scales. Pore type, pore size, pore connectivity, wettability, mineralogy and fabric are among the aspects that are best addressed with such techniques in microporous reservoirs. Questions that these methods address will be discussed, along with their relevance to petrophysical interpretation and their place in formation evaluation workflows. Case studies will be shown to illustrate application of pore-scale imaging to assessing tight sandstone and “shale” plays.

Applications to tight sandstone in the Green River Formation in the Uinta Basin in Utah include imaging wettability with FESEM and associating altered wettability with specific mineral phases; and detecting formation damage mechanisms in SEM images taken before and after exposure to completion fluids. Shale examples of workflows include combining MicroCT images, mineral maps, FESEM images, and FIBSEM image data to yield both insight and quantitative results.

Issues with image data, potential pitfalls in interpretation, and new frontiers for core analysis based on imaging techniques will also be covered.

Biography

Terri Olson is a consulting petrophysicist at Digital Rock Petrophysics in Golden. She has over 30 years of experience in the oil and gas industry as a geologist and petrophysicist. Terri earned B. A. and M.A. degrees in geology from Colorado College and Dartmouth College, respectively. She attended Amoco’s petrophysics school in Tulsa (1988-89). After BP’s acquisition of Amoco in 2000, Terri returned to Denver from Stavanger, Norway, and has since worked for Tom Brown, Encana, EOG, and FEI Oil & Gas.In the volunteer arena, Terri has been active in both geological and petrophysical professional societies. She served as Chair of both the RMAG and AAPG Publications Committees, and was Senior Associate Editor for Unconventionals for AAPG for 3 years. She co-edited a Piceance Basin guidebook for RMAG in 2003, and edited a 2016 Memoir for AAPG, Unconventional Reservoir Pore Systems. She received a distinguished service award from RMAG in 2007 and from AAPG in 2016. Terri has served on the boards of directors of RMAG and DWLS, and is currently President-Elect of RMAG. She is a member of AAPG, SPWLA, SPE, RMAG, and DWLS.

The Role of Rock Properties in Unconventional Resource Plays

Mike Mullen (Stimulation Petrophysics Consulting)

A key component of completing unconventional reservoirs is the fracture stimulation treatment. So how does one determine the optimal treatment volumes, stage spacing and entry points? It could be a matter of trial and error. This is typically the method used by a lot of operators. It is also an expensive learning tool requiring a number of field trials. Another option would be to use modern day frac modeling simulation programs to run numerous “what if” scenarios to determine the ideal stage spacing, entry points, fluid and proppant volumes as part of an engineered completion program. The heart of these frac modeling programs is a robust rock property model, pore pressure, temperature and overburden gradient. The primary mechanical rock property inputs are Poisson’s Ratio and Young’s Modulus.

Typically mechanical rock properties are determined by running modern day Dipole Sonic logs. In Unconventional plays, sonic logs are not always available in the pilot well and rarely run in the lateral wellbore. In these cases, rock properties can be estimated using neural networks or deterministic models. To advance the state of completions from “poke and hope” completion optimization scheme to a more engineered completion, rock properties evaluation need to be estimated in vertical and horizontal wells for input to fracture stimulation design and modeling programs. So routinely calculating mechanical rock properties need to be included as part of the unconventional resources workflow toolkit.

Biography

Mike is the president and founder of Stimulation Petrophysics Consulting, LLC. He has over 40 years of oil field wireline logging and formation evaluation experience. During his 25-year career with Halliburton, Mike helped develop techniques for the analysis of conventional and unconventional reservoirs and deriving mechanical rock properties used in stimulation design and optimization.