The members and officers of the SPWLA Tulsa Chapter are proud to revive one of the founding chapters of this prestigious International Society. Please join us as we continue to promote and advance the science of formation evaluation.
Due to Concerns over Covid19 the Tulsa SPWLA Chapter is going to a Virtual Format for the Fall 2020 Chapter Meetings / Presentations.
The Tulsa SPWLA Chapter thanks the University of Tulsa for its hospitality in hosting our Luncheon Meetings for the 2019 / 2020 season and we especially appreciate the efforts of Buford Pollett, J.D., Genave King Rogers Assistant Professor of Energy Law and Commerce without who's efforts our meeting would not have been possible.
Tulsa SPWLA Chapter - Virtual Meeting
April 8, 2021 - 11:30 am to 12:30 pm
A Link to the Webinar will be attached to the email announcement for this Presentation
Conclusive Proof of Weak Bedding Planes in the Marcellus Shale and Proposed Mitigation Strategies
Speaker: Julie Kowan
Authors: Julie Kowan, Baker Hughes; Luke Schanken, EQT Corporation and Robert Jacobi, Geoscience Consulting and University at Buffalo
Wellbore instability has been experienced in areas of the Marcellus Shale and can become particularly troublesome in the superlaterals that are becoming more prevalent in that play. Often the instability while drilling these very long lateral wells is minimal; problems are more likely to occur while tripping out after reaching TD. The most common instability events when pulling out of the hole are tight hole, pack-off and stuck pipe and are often accompanied by excessive cavings. These problems often worsen with time, indicating there is some time-dependence to the failure mechanism.
In order to develop effective mitigation strategies to combat the instability, it is imperative that the failure mechanism be correctly identified. Previous publications (Kowan and Ong, 2016; Addis et al. 2016; Riley et al. 2012) have suggested that bedding planes may play a role in some of the drilling problems experienced in the Marcellus Shale. This case study provides conclusive proof of weak bedding plane failure along a lateral well in the Marcellus Shale, where over one thousand feet of anisotropic failure were captured with a LWD image tool.
This image not only provided confirmation of the presence and failure of weak bedding planes in the Marcellus Shale, but was also used to validate an existing geomechanical model for the area. Validating the model gave the operator more confidence in the mitigation strategies developed from that geomechanical model, which had been based on the assumption that weak bedding was contributing to difficulty experienced on multiple lateral wells when tripping out of the hole.
This case study begins with an overview of the geomechanical model, including the drilling history, stress/pore pressure model and rock properties. Next, some highlights from the image log, showing anisotropic bedding plane failure, are featured, as well as a comparison of the image to the geomechanical model. This case study concludes with proposed mitigation strategies that could be implemented to limit the risks posed by weak beds and to minimize instability, when drilling laterals in the Marcellus Shale in this area or similarly complex areas.
Julie Kowan, Geomechanics Advisor: Ms. Kowan has over 16 years’ experience enabling operators to drill safer, more cost-effective wells and plan field development by reducing non-productive time (NPT) due to wellbore instability and improving production. She has expertise in unconventional reservoirs, pore pressure prediction, stress constraint, wellbore stability, fracture permeability and compaction. Ms. Kowan began her career as a Geomechanics Associate at GeoMechanics International (GMI) in 2005 before being promoted to Specialist and Advisor positions at GMI and Baker Hughes. From 2016 to 2018, she ran her own successful consulting company, J. Kowan Consulting, LLC, before re-joining Baker Hughes in 2018. Ms. Kowan earned a Master of Science in Geology from Brown University and a Bachelor of Science in Geology from Rutgers University. She served as the Vice President of the Boston Chapter of the SPWLA from 2017-2019 and as Secretary from 2015-2017. Ms. Kowan was also named a SPWLA Distinguished Speaker for the 2020-2021 series.
DETERMINING WATER-FILLED POROSITY OF TIGHT OIL RESERVOIRS WITH
A NEW INTERPRETATION METHOD FOR DIELECTRIC DISPERSION MEASUREMENTS
Speaker : Nikita Seleznev
Authors : Nikita Seleznev, Tarek M. Habashy, Michel Claverie, Schlumberger; Hanming Wang, Haijing Wang,
Chevron U.S.A. Inc.; Amir Hermes, Jason Gendur, Ling Feng, Mary Ellen Loan, Schlumberger
Tight oil reservoirs present a unique opportunity for dielectric dispersion logging. Dielectric logging is sensitive to the
water content and provides water-filled porosity without having to know Archie’s empirical parameters or water salinities,
as is required with resistivity log interpretation. Moreover, because of the extremely low permeability of the shale
reservoirs, there is effectively no invasion of the borehole fluids into the formation. Thus, in these reservoirs, dielectric
dispersion logging directly provides the water-filled porosity of the undisturbed zone.
In this paper, we investigate the interpretation of the dielectric dispersion measurements in tight oil formations. A
representative core collection was obtained from two intervals in a field. The core material was characterized in terms of
lithology and total organic carbon (TOC) content. The cores were cleaned and saturated with brines that match the
formation water salinities.
Next, the dielectric dispersion measurements on cores were obtained under controlled
laboratory conditions of pressure, temperature, and brine salinity.
On the basis of the analysis we conducted on these data, we have developed a new method for the interpretation of
multifrequency dielectric logs in tight oil reservoirs. The new method has a significant advantage over the existing
approaches because it does not require an input for either matrix or hydrocarbon permittivities, including kerogen
permittivity, to derive water-filled porosity as is the case with the existing approaches. The new method enables the
elimination of all associated uncertainties with formation mineral models in complex lithologies, unknown mineral
permittivity endpoints, and, most importantly, the poorly defined permittivity of kerogen. The new method requires only
the relatively well-known input of formation temperature. Thus, the new method provides a more robust, streamlined,
and consistent interpretation of the dielectric dispersion logs in tight oil and reduces the uncertainty on the estimate of
hydrocarbon in place.
Biography: Nikita Seleznev received his PhD in Petrophysics from the Delft University of Technology in The
Netherlands. He joined Schlumberger-Doll Research in 2000 and held various positions, including
Petrophysics Program Manager and Principal Scientist. During his tenure, Nikita conducted research
and led R&D projects on various aspects of petrophysics, including nuclear spectroscopy,
petrophysical evaluation systems, and dielectric as well as resistivity logging tools and techniques.
Additionally, he studied applications of the induced polarization measurements for formation
evaluation and a joint interpretation of the electromagnetic measurements across a wide frequency
band. He has published more than 30 papers and holds 9 US patents. Nikita served as an SPWLA Technology Committee member from 2017-2019.
Comparing Petrophysical Properties To Horizontal Wells: It’s Harder Than It Seems
When it comes to relating vertical petrophysical wells to horizontal production. There are many problems, some ideas and perhaps no good solutions. I want to discuss some ideas that have come up in the last few years.
Recently there has been a large volume of publications on machine learning(ML) in petrophysics and reservoir engineering. While there is no doubt that ML and deep learning will play an important role in the petrophysicist’s tool kit in the 21st century, it is important to keep an eye on how data is related. Just like any model, ML will return gibberish if the data is not related, not organized properly or not quality checked for accuracy. There are of course methods to find outliers and extraneous data but that is not the focus of this talk. On the contrary, I will present some ideas on how to relate vertical well petrophysical models to horizontal well production using a physics based framework. Then we can apply the usual ML tricks.
There are many variables to consider, a simple net pay model will be unlikely to produce results but it is the foundation of any petrophysical endeavor. Additional variables to consider are hydraulic fracture height and half length (modeled) in addition to well orientation. Fluid composition, pressure are also important. One must also consider what we are comparing to on the production side and do normalization for that. EUR’s are often cited as the most important metric, but they are often highly inaccurate unless the well(s) have reached a boundary condition. Therefore it is important to keep in mind which production metrics you are trying to correlate too. In this talk we will show some real world examples of trying to untangle this mess.
Thus, this presentation is ideas about relating vertical petrophysical wells to horizontal production. There will be many problems, some solutions and hopefully good discussion.
Adam Haecker is a Senior Petrophysicist and Supervisor of Petrophysics at Continental Resources in Oklahoma City, OK. Continental Resources, is one of the most active drillers in the country, with activity in Southern Oklahoma and North Dakota. He is currently researching a diverse range of topics including relations of permeability to MICP, organic matter density with maturity and relations between GOR to productivity in organic shales. He obtained his B.S. in geology from Texas A&M University in 2007. He joined his current company in 2014 and has been in the E&P industry for twelve years. Previously with Chesapeake Energy, Cabot Oil and Gas and Weatherford Wireline. He is the North American Director 1 on the international board of the SPWLA. His hobbies include model building and learning Japanese.頑張って!
Electrical Properties of Shales
Mewbourne School of Petroleum and Geological Engineering
University of Oklahoma
The determination of water saturation based on electrical resistivity logs relies on knowing the electrical properties of the reservoir rocks. However, measurements of these electrical properties for unconventional shale reservoirs are scarce in the literature. This scarcity increases uncertainties of water saturation estimates and prevents reliable hydrocarbon reserves estimations.
To improve water saturation estimates and understand the factors controlling electrical properties such as the Archie cementation exponent (m) in shales, we measured the electrical resistivity of 95 brine saturated unconventional shale samples collected from the immature, oil and gas windows of the Woodford and Wolfcamp shales. These samples were characterized by measurements of petrophysical properties such as TOC, mineralogy, and crushed rock porosity. In addition to these measurements, we have also modeled the flow of electrical current through porous media.
Measurements of resistivity on the brine saturated samples revealed that maturity exerts a minor control on the cementation exponent. The linear relationship between TOC and cementation exponent allows the computation of cementation with the knowledge of TOC.
Ali Tinni is a faculty in the Petroleum Engineering Department of the University of Oklahoma. He teaches petrophysics and reservoir engineering courses. His current research interests include fluid flow and storage as well as EOR in unconventional reservoirs. He holds Master’s and PhD degree in Petroleum Engineering from the University of Oklahoma.
Characterization of the Caney Shale, Southern Oklahoma
By Yulun Wang
Wang, Yulun; Cains, Julie; Cox, Ian; Puckette, Jim; Grammer, Mike; Pashin, Jack; Wethington, Conn and Cory Hart
Boone Pickens School of Geology, Oklahoma State University
The Meramecian-Chesterian Caney Shale is partially time-equivalent to the highly productive Fayetteville and Barnett shales, but Caney production is sparse and unpredictable. In the Ardmore and Marietta basins, the Caney Shale is over 215 m (700 feet) thick, rich in total organic carbon and in the oil window. To assess Caney production potential, depositional processes and facies must be interpreted within a sequence stratigraphic framework. Other important factors are the 3D pore architecture, petrophysical and geomechanical properties and natural fractures. Preliminary results indicate that the Caney Shale contains a variety of mixed carbonate-siliciclastic facies established based upon mineralogy, rock fabric, grain texture and dominant sedimentary and biogenic structures. Siliciclastic-rich facies are mainly massive-bedded mudstone and calcareous to muddy siltstone, burrowed to bioturbated silty mudstone, and bioturbated siltstone. Carbonate-rich rocks include packstone-grainstone, laminated carbonate and silty mudstone, packstone-rudstone, and dolomitic facies. These facies are associated with a variety of depositional processes, such as low energy background sedimentation of the siliciclastic-rich facies and high energy event deposition (e.g., turbidity current, debris flow, storms/longshore currents) of the carbonate-rich facies. Based on these observations, Caney sediments in southern Oklahoma were likely deposited on a gently dipping slope or ramp environment where lower energy deposits were episodically interrupted by high energy deposits sourced from shallower water carbonates. Vertically, facies show variable patterns, some occur repetitively, whereas others are concentrated in certain intervals or scattered throughout the section. These patterns reflect cyclic, systematic shifts in depositional processes across this region and critical for constructing a regional stratigraphic framework and mapping facies and reservoir distribution. Visible pores are not evident in core or thin sections and scanning electron microscopy reveals that pore types appear to reflect different rock fabrics. Interparticle pores dominate calcareous siltstone and carbonate-rich facies, whereas organic-rich mudstone contains a variety of pore types but is dominated by organic matter pores. On-going work includes detailed characterization of pore geometry and distribution and their relationship to rock types, and the relationships among sonic velocity, pore systems architecture, and permeability.
Yulun Wang is a post-doctoral researcher in the Boone Pickens School of Geology of the Oklahoma State University, focusing on the integrated reservoir characterization of the Caney Shale play in southern Oklahoma. Yulun was born in Panjin, which is a city powered by a major oil field in northeastern China. Driven by his curiosity about the pumpjacks in his backyard, Yulun earned his Bachelor’s degree in Petroleum Geology from Jilin University in China. He later moved to the University of Tulsa and worked with Dr. Robert W. Scott on the Lower Cretaceous shallow-marine carbonate strata in southwest Texas, which earned him a M.S. degree in Geology. Learning about the boom of unconventional resource plays at that time, Yulun became interested in characterizing these reservoirs and moved to the Boone Pickens School of Geology in the Oklahoma State University to pursue a Ph.D. degree. For his dissertation research which was mentored by Dr. G. Michael Grammer, Yulun focused on characterizing the sequence stratigraphic framework, natural fracture system, and rock mechanical properties of the unconventional “Mississippian Limestone”/STACK play in north-central Oklahoma, USA. Benefited from collaborations with industrial sponsors and the University of Miami (CSL – Center for Carbonate Research), Yulun also worked on the Wolfcamp Formation in the Permian Basin and the Vaca Muerta Formation in Argentina. Yulun was the recipient of the AAPG Grants-in-aid Award (2016, 2017) and the Oklahoma Geological Foundation Davis Geology Fellowship (2015), and was a Geology Intern at Tiptop Oil and Gas (Sinopec) (Oklahoma City, 2016).
The Tulsa Chapter appreciates Dick Merkel's October informative presentation and his continued work on the petrophysical properties of Clays.
Electrical Properties of Clays
Clay electrical properties are more complex than simply the clay diagenesis or clay morphology because the clay fabric makes its resistivity a tensor. Even before three dimensional resistivity tools were developed, tensor properties of clays could be observed with the difference between the vertical vs. horizontal wells and/or between the responses between induction vs. laterolog measurements. Modern NMR and dielectric tools and processing allows us to determine clay bound water directly. As a result, in many cases we now can separate out clay electrical properties from the response of the reservoir rock matrix. This knowledge limits the shaly sand petrophysical models that are numerically stable with these measured log electrical properties of clays.
Analysis of XRD data to determine the clay bound water volume is shown to verify NMR and dielectric VCBW inversions and can be used to calibrate deterministic clay volume models. Examples in conventional and unconventional reservoirs in the Rocky Mountains are shown with various combinations of triple combo, NMR, and dielectric logs combined with XRD core measurements. This type of analysis helps in determining free water and reservoir wettability both of which impact reservoir reserves, recoverability, and economics.
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 Encana and Newfield where he worked on teams that developed reservoir models for conventional and 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 on evaluating new logging tools and technology, and developing techniques for their application in Marathon’s reservoirs worldwide. For the past thirty years, the emphasis of his work has been on the rock physics of NMR and dielectric log and core measurements and their interpretation. 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.
We wish to Thank Chelsea Newgord for her excellent Presentation during our September Virtual Meeting
A New Workflow for Joint Interpretation of Electrical Resistivity and NMR Measurements to Simultaneously Estimate Wettability and Water Saturation
Chelsea Newgord, Artur Posenato Garcia, and Zoya Heidari
The University of Texas at Austin
Wettability of rocks can be assessed from interpretation of borehole geophysical measurements such as electrical resistivity and Nuclear Magnetic Resonance (NMR). These wettability models often require additional inputs (e.g., water saturation, porosity, and pore-geometry-related parameters), which are difficult to obtain independently. Consequently, a multi-physics workflow that integrates resistivity and NMR measurements can reduce the number of input parameters, resulting in a more accurate and robust wettability assessment. The objectives of this work are (i) to introduce the workflow for joint interpretation of resistivity and NMR measurements to simultaneously estimate wettability and water saturation, and (ii) to verify the reliability of estimates of wettability and water saturation by comparison to experimentally measured contact angles, Amott Indices, and gravimetrically assessed water saturation.
The new workflow for assessing wettability and water saturation combines non-linear resistivity- and NMR-based rock physics models. The inputs to the resistivity-based wettability model include the resistivity of the rock-fluid system and brine, porosity, and pore-geometry-related parameters. The NMR-based wettability model requires the transverse (T2) responses of the rock-fluid system, of the saturating fluids, and of water-wet water-saturated and oil-wet oil-saturated rocks. To verify the reliability of the new integrated workflow, we perform resistivity and NMR measurements on core samples from different rock types, covering a range of wettability and water saturation levels. These measurements are inputs to the non-linear models, which are simultaneously solved to estimate wettability and water saturation for each core sample. We verify the reliability of wettability estimates by comparison to the Amott Index and contact angle measurements, and the water saturation estimates by comparison to the gravimetrically measured water saturation.
We successfully verified the reliability of the new method for joint interpretation of resistivity and NMR measurements to estimate wettability and water saturation of limestone and sandstone core samples. For water saturation levels ranging from irreducible water saturation to residual oil saturation, we observed an average relative error of 11% between the gravimetrically assessed and the model-estimated water saturation. It is challenging to estimate water saturation in rocks with multi-modal pore-size distribution uniquely from the interpretation of NMR measurements. The introduced integrated workflow improved the accuracy of water saturation estimates in rocks with complex pore structure. For the wettability ranging from oil-wet to water-wet, we observed an average absolute difference of 0.15 between the experimentally measured Amott Index and the model-estimated wettability. These model-estimated wettability values were also consistent with the contact angle measurements. It should be noted that the new workflow relies on physically-meaningful and measurable parameters, which minimizes calibration efforts. Furthermore, the multi-physics workflow eliminates the non-uniqueness associated with wettability and water saturation estimates obtained from independent interpretation of NMR and resistivity measurements.
Chelsea Newgord recently received her MS in petroleum engineering from The University of Texas at Austin. She currently works in the Formation Evaluation group at ExxonMobil in Houston. Previously, she worked as a reservoir geophysicist at Sigma Cubed Integrated Reservoir Services in Denver from 2012–2017. She holds a BS degree (2012) in geophysical engineering from Colorado School of Mines, with minors in geology and public affairs. She was designated as a Distinguished Speaker for 2018–2019 and 2019–2020 by SPWLA. She is a member of SPWLA, SPE, and SEG. Her research interests include core analysis, formation evaluation, and multi-disciplinary reservoir characterization.
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