2018 SPWLA Formation Testing SIG Meeting: Presentation Abstracts 7:30 am – 4:30 pm March 7th, 2018

Repsol Auditorium, 2455 Technology Forest Blvd, The Woodlands, TX 77381 Title: Using Formation Testing to Guide G&G Modeling and Field Development – a Connectivity / Fault Block Migration study based on DFA Authors: Li Chen, Julia C. Forsythe, SCHLUMBERGER; Tim Wilkinson, Ben Winkelman, TALOS; John Meyer, DEEP GULF ENERGY; Jesus A. Canas, Weixin Xu, Soraya S. Betancourt, Dan Shan, Ron S. Hayden, Oliver C. Mullins, SCHLUMBERGER. Abstract: Reservoir architecture, the size and reservoir quality of producing bodies remain a central concern particularly in deepwater environment. This case study describes a Talos Energy discovery in deep-water Gulf of Mexico, Tornado field, from a Pliocene formation. The high-quality seismic imaging delineated the sand bodies with a gross pay of 400 feet. The 2 wellbores in the main block A and one wellbore in adjacent block C all exhibit these stacked sands but separated by an intervening shale break. The lateral and vertical connectivity of the reservoir is of major concern for field development planning regarding reserves and completion strategy. The RFG (Reservoir Fluid Geodynamics) workflow is applied on this field for connectivity study, with integration of the advanced DFA (Downhole Fluid Analysis) data from wireline formation testing, advanced analytical and geochemical analysis of the oil, and laboratory PVT data. The advanced DFA data includes fluid color (asphaltene), composition, Gas-Oil-Ratio (GOR), density, viscosity, and fluorescence yield to help drawing a real-time assessment of connectivity in real-time, which help to optimize the data acquisition and guide the vertical interference testing to allow the early completion decision. The DFA data was analyzed using the Flory-Huggins-Zuo Equation of State for asphaltene gradients and the Cubic Equation of state for GOR gradients as is the norm for RFG studies. The resulting DFA-RFG analysis shows that in the main block A, the fluids in the upper and lower sands appear to be separately equilibrated, in spite of the young age of the reservoir, indicating there is good lateral connectivity in each sand. The asphaltene content of the oil in the upper sand is slightly, yet significantly smaller, than that in the lower sand indicating that the intervening shale might be a laterally extensive baffle or possibly a barrier. Subtleties in the DFA data are more consistent with the shale being a baffle. Moreover, the biomarker analysis shows that all oils encountered are indistinguishable from a petroleum system perspective. This reinforces the DFA-RFG interpretation. The paleo flow analysis based on high definition borehole images integrated with seismic interpretation confirmed from geology realization with upper sand scouring the interventional shale. the most probably interpretation is that the shale is a baffle. The sands from the well in the adjacent block C shows the vertical shifting of asphaltene distribution from block A, which is concluded to be the fault block migration of block C from A, with ~400ft fault throw estimation. The fluid properties including asphaltene content, API gravity, methane stable isotope, GOR, density all consistently confirmed the

fault block migration with differential primary biogenic methane late gas charge between 2 blocks. The connectivity understanding from wireline formation testing guides the integration of geophysics, geology borehole imaging, petrophysics and optimized field development plan. The field connectivity conclusions have been confirmed by the 1 year production history matching. Presenter’s Bio: Li Chen is a Principal Reservoir Engineer with Schlumberger, Houston, Texas, USA. He provided the reservoir engineering support primarily on Formation Testing and Reservoir Fluid Geodynamics projects from US and overseas. He holds a Master’s Degree in Reservoir Engineering from China Petroleum University. His previous positions include Reservoir Domain Champion, project manager, and answer product analyst in Houston and Beijing. He has co-author about 40 technical papers and co-invented 10 US patents and applications. ////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////// Title: Wireline Formation Fluid Sampling: From Making the Value Case, to Applying the Lessons Learned. A Guide to Improve Rate of Success While Taking Fluid Samples in the Lower for Longer Oil Price Environment. Authors: Wilson Pineda, Eric Soza, John Bergeron John Williams and Doris Gonzalez: BP Abstract: Downhole fluid samples are one of the most critical pieces of information for reservoir characterization. They are used to inform fluid properties and are a key input into the understanding and prediction of reservoir performance and recovery. Understanding fluid properties is also critical to efficiently operate the well and reduce flow assurance problems. As lower commodity prices are the new norm in the industry, every effort should be made to ensure fluid sample acquisition is successful, this in turn will help to keep the sample collection cost as expected and fluid information will be available for the life of field development. The case to collect fluid samples requires balancing the value of the information versus risk and cost. The planning should consider many factors from vendors’ experience, well complexity, deployment options, formation fluids, borehole fluids, real time contamination monitoring, probe positioning, etc. Job planning should also cover the selection of the proper technology like probe type, mud filters, pumps, samples bottles, etc. During the operation, decisions are typically needed to update the program based on new available information or unexpected operational challenges. Once the operation is completed, lessons learned should be properly captured and shared with vendor as part of continuous improvement. Efforts to increase efficiency should include the reduction of tool plugging and tool fishing among others. This paper is intended to share lessons learned from several years of collecting fluid samples in several fields using multiple wireline vendors. The work includes building the business case for fluid sampling, planning, execution and capturing lessons learned. Sampling environments include unconsolidated sands, highly depleted reservoirs and

deep deviated wells where conveyance and depth control are challenging. Many of the operations were performed in wellbores with high concentration of lost circulation material (LCM) including stress cage as part of the drilling mud formulation. Presenter’s Bio: Wilson Pineda is a Petrophysicist at BP Exploration and Production in Houston. He holds a BS degree in electrical engineering from Yacambú University (UNY) and a master in electrical engineering from National Polytechnic Experimental University (UNEXPO), both in Venezuela. Before joining BP, he spent 16 years in field operations and product development with the wireline division of Baker Hughes working in several countries. Wilson specializes in designing formation evaluation, sampling and coring plans to answer complex reservoir problems and integrating data for petrophysical analysis of deep water fields. ////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////// Title: Wireline Pressure Cores: Simultaneous Recovery and Analysis of Reservoir Rocks and Fluids Author: Don Westacott Abstract: During an oil and gas exploration and development project, many reservoir properties must be evaluated to ensure success, both economically and operationally. These parameters include determining the amount of original hydrocarbon in place, the amount of residual hydrocarbon in place after years of production, and reservoir drive mechanisms. Additionally, an accurate analysis of the hydrocarbon properties is necessary to ensure that the reservoir is completed and produced appropriately. Collecting core samples from the reservoir is one way to obtain this information. This method, however, exhibits limitations and uncertainty resulting from the way that the core samples are traditionally obtained and retrieved to surface. This paper details a new sidewall coring technology designed to keep cores in a sealed vessel to prevent the loss of formation fluids. Collection of the lost formation fluids, rather than estimation of lost fluids, leads to an improved analysis of reservoir hydrocarbon volumes when compared to traditional coring systems. The location and saturations of formation fluids within the reservoir is also of importance in evaluating reservoir drive mechanisms. Additionally, collection of these formation fluids allows for analysis of the fluid properties which are critical in the design of completion and production strategy for a reservoir. Finally, shale gas, tight oil, and mature field applications of the technology with case histories in the Marcellus, Bakken, San Andres formations are discussed.

Presenter’s Bio: Don Westacott is the Chief Advisor, Global Unconventional Reservoirs for Halliburton. Don has pursued a lifelong interest in science and engineering beginning as a youth in western Canada. Don continued this interest and graduated from the University of Alberta receiving a Bachelor Science in Electrical Engineering. During the last 35 years he has worked in E & P industry in Canada, the United States, Europe, the Middle East and the Far East. Don’s unconventional reservoir analysis work began in the early 1980’s when he worked for Canadian Hunter Exploration. Don worked for the legendary oil and gas finder John Allen Masters and with his mentoring developed the fundamental skills of oil and gas exploration that he would apply through his continued career. Don developed reservoir characterization expertise while working for Apache Corporation, Carigali-Hess Malaysia, ResTech Houston and Newfield Exploration. His technical area of interest lead to publications of nuclear magnetic resonance applied to reservoir characterization. Don Westacott strongly considers training and technology transfer as an important part of his role within the E&P industry. Recently Don accepted a role as guest lecturer at the Colorado School of Mines providing instruction to a new generation of petroleum engineering students. Don was honored this year to be the Distinguish Speaker at the Harvard University Energy Panel Arab Conference. Don and his wife Marilyn enjoy the success of their sons Matthew and Andrew.

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Title: Viscous Oil, AOP and Tar Mats Understood within a Single Basic Chemistry Formalism; a Reservoir Fluids Geodynamic Approach Author: Oliver C. Mullins, Schlumberger Abstract: Asphaltenes have been viewed as enigmatic; in fact, asphaltenes exhibit remarkable, reliable systematics for oil reservoirs around the world. The Yen-Mullins model specifies three distinct species of asphaltenes reflecting different degrees of asphaltene solvency in crude oils. With this knowledge, a very simple polymer solution theory modified for application in oilfields, the Flory-Huggins-Zuo Equation of State,

accounts for asphaltene gradients and stability in oil reservoirs. Equilibrated asphaltenes imply reservoir connectivity; different reservoir studies show this for each of the three species and for some combinations of these species from the Yen-Mullins model. The reservoir studies show which asphaltene species forms which is shown to relate to asphaltene stability. The stability model for asphaltenes exploits simple concepts of basic solution chemistry and applies to reservoirs globally. Thus, asphaltene gradients are related directly to asphaltene stability. In turn asphaltene stability relates to viscous oil formation, tar mat formation and asphaltene onset pressure. Oilfield factors which influence asphaltene stability include gas charging into oil reservoirs which destabilizes asphaltenes, and biodegradation which removes n-alkanes and can stabilize (yet concentrate) asphaltenes. Finally, the ability to identify equilibrated oil columns necessarily identifies disequilibrium oil columns providing great insights into reservoir fluid geodynamical processes. This powerful framework has been applied to 40 oilfields worldwide with great effectiveness addressing a large number of geological and fluid uncertainties about reservoirs. Presenter’s Bio: Dr. Oliver C. Mullins is a Schlumberger Fellow. He is the primary originator of Downhole Fluid Analysis (DFA) in well logging. Dr. Mullins also leads an active research group in petroleum science leading to the Yen-Mullins model of asphaltenes and the Flory-Huggins-Zuo Equation of State. His current interests include utilizing DFA technology and new asphaltene science to perform novel reservoir evaluation. This work is subsumed in the newly codified technical discipline he is leading “reservoir fluid geodynamics” that accounts for processes dictating fluid and tar distributions in reservoirs. He has won several awards including the “SPWLA Gold Medal for Technical Achievement” and two Schlumberger Gold Medals. In 2018, he will receive the “George A. Olah Award of Hydrocarbon or Petroleum Chemistry,” named after a Nobel laureate and award recipient (Olah), from the American Chemical Society. He has been elected member of the National Academy of Engineering. He has been Distinguished Lecturer 6 times for SPWLA and SPE. He authored the award-winning book The Physics of Reservoir Fluids; Discovery through Downhole Fluid Analysis, coedited 3 books and coauthored 14 chapters on asphaltenes and related topics. He has coauthored 270 publications, ~½ on petroleum science, ~½ on applications, and has co-invented 115 allowed US patents. He has accumulated >15,000 citations on Google Scholar to his work. He is Fellow of two professional societies and is Adjunct Professor of Petroleum Engineering at Texas A&M University.

//////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////// Title: Using Advanced LWD Fluid Analysis and Sampling Technology to efficiently define Fluid Types and Contacts in Challenging Reservoirs Author: Femi Adegbola Abstract: Pressure testing and sampling in complex thin bedded sand shale formations can be a daunting task, as these formations comprise of centimetre to meter scale sandstones. The inter-bedded shales make positioning the formation tester probe in suitable sand difficult. This case study shows challenges from formations with interbedded sand shale sequences, having two or more fluids in the sands. An innovative solution was presented to the operator to enable faster decision making in real-time, by characterizing reservoir fluids using an efficient pump and analysis solution. Real-time identification of formation fluids, with high uncertainty in the pressure gradient analysis results, is possible with the unique high definition fluid typing solution. This enabled the operator to get a far clearer picture of the reservoir. With this method the operator was able to test connected zones which were difficult to delineate by pressure alone, due to a limited pressure profile. Real – time high definition fluid typing was conducted in multiple intervals in the wellbore to clarify contacts and fluid types, and accurately map potential perforation zones, which would have been near impossible from standard logs and pressure data alone. The high definition fluid typing solution clearly identified oil, water and gas, in the limited amount of time and volume requested by the client. During the oil fluid typing, post pump out phase separation tests were conducted to provide extra downhole information, which gave extra confidence to the accuracy of the fluid typing analysis. This unique solution meant that there were no sample tanks which were needed to be filled and analyzed after the successful operation, and it provided the operator with high definition pressure testing results and fluid types. Though fluid sampling can be achieved in thin reservoirs, the situation here was different – the oil-water contact was in a located in the thin beds, as seen from the

magnetic resonance result. The operator needed to know the actual formation fluid present in the sand. Only one pressure point was acquired in the thin bedded sand and nothing could be done with just one point as regards gradients. So rather than perforating a zone of interest and having early influx of water production, the new innovative fluid identification technology was used to identify the fluid type in real-time, saving the operator time and money. Presenter’s Bio: Femi Adegbola is the Baker Hughes Global Product Manager for Fluid Characterization and Testing while Drilling. With 21 years of industry experience, Femi has a broad knowledge base and in-depth understanding of the role of Formation Sampling and Testing technology in addressing the industries Reservoir Description and Development Challenges. Femi has also held roles in Operations, Sales and Geoscience Management and has worked in various locations which include Nigeria, UK, Malaysia, USA and Iraq. He is an active member of both SPE and SPWLA and holds a B.Eng. in Mechanical Engineering from Imperial College, London. (femi.adegbola@bhge.com)

//////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////// Title: Tool Malfunction: Learning the Hard Way! Author: Mayank Malik Abstract: On a recent logging job, a formation tester with a single packer was used to acquire formation water samples for regulatory work: if salinity is higher than 10k ppm, produced water can be injected in the zone. During operation, due to high lost circulation material in the drilling mud, the formation tester tool encountered severe plugging and malfunctioned. End results is that the sampling job that was planned to take 2-3 hrs ended up taking 10 hrs and another run (more rig time). Eventually, low contamination samples were successfully collected but the logging job was sub-optimal and lessons were learned the hard way. The talk presents history matching results and several what-if scenarios on how long sampling would have been if tool worked optimally with various probe configurations.

Presenter’s Bio: Mayank Malik is the Formation Testing Expert in Chevron's Energy Technology Company. He holds 3 degrees from three countries: B.S. in Mechanical Engineering from Delhi College of Engineering (India), MS in Mechanical Engineering from University of Toronto (Canada), and Ph.D. in Petroleum Engineering from The University of Texas at Austin (USA). Malik has authored numerous papers on petrophysics, formation testing, and microfracturing. He is the founder and past-Chairman of the SPWLA Formation Testing Special Interest Group (FT SIG). Malik received the SPWLA Meritorious Service award in 2017. He is a SPE Distinguished Lecturer and SPWLA Distinguished Speaker for 2016-17. //////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////// Title: A Review of the State-of-the-Art for Compositional Modeling in Shales Author: Deepak Devegowda Abstract: Accurate PVT modeling and compositional simulation are essential for understanding primary production and enhanced oil recovery. However, several recent studies show that classical methods may actually be incorrect for modeling flow and storage in nanoporous shales. In several instances, field data suggests extended periods of constant CGR (or GOR) production profiles although the bottom hole flowing pressure is known to be below the fluid saturation pressure. In a few other cases, compositional analysis of produced fluid samples indicate that some in-situ fractionation might be occurring. Because these observations have a direct impact on well spacing, well life predictions, reserves per well and project economics, several theories have been postulated to attempt an explanation for these field observations. Primarily, the central theme of these theories is the pore proximity effect that occurs when a large percentage of confined fluid molecules come under the influence of the pore walls. This is especially true in shale nanopores because the relative sizes of the molecules and the pores or pore throats are comparable. This pore proximity effect has been reported to manifest itself in several ways, either through a change in the fluid critical properties or via a change in vapor-liquid equilibrium because of capillary pressure considerations. Transport of multicomponent fluids has also been addressed through other theories that focus on the non-Darcy flow of gases and the resulting fractionation effect because of the different non-Darcy slip flow effects on lighter and heavier molecules. Multicomponent adsorption in shale nanopores also continues to be poorly understood but is known to influence early-life and late-life production profiles. This talk provides a concise review of the current state-of-the art in describing PVT modeling for shales and also provides a roadmap for future work including modeling studies and laboratory experiments to comprehensively integrate shale pore size distribution, pore connectivity, multicomponent adsorption, PVT sampling and modeling and short- and long-term production trends. The primary purpose of this talk is to provide an overview of theoretical and experimental advances in understanding PVT

behavior in shales and underscore the challenges with PVT modeling in shales and discuss potential avenues for further research. Presenter’s Bio: Deepak Devegowda is an Associate Professor, Graduate Liaison & Mewbourne Chair in Petroleum Engineering #1. His Research Interests include Reservoir characterization & uncertainty assessment, Geostatistics and Unconventional oil & gas reservoir engineering. His education includes a B.Tech., Electrical Engineering, Indian Institute of Technology, 1998; M.S., Petroleum Engineering, Texas A&M University, 2003: Ph.D., Petroleum Engineering, Texas A&M University, 2008 //////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////// Title: Wireline Micro-Frac & PVT Fluid Sampling, New Open Hole Reservoir Diagnostics for Unconventionals Author: Neil Stegent Abstract: While the basic application of wireline straddle packer injection stress testing has existed for a number of years, the industry has been slow to accept it for perceived differential stress constraints and differences from conventional cased hole DFIT analysis. Recent technical and interpretation methodologies have been developed to address both the fracture initiation and closure part of the deliverables for this service, but also the novel, post-frac flow-back, PVT sample testing of the packer isolated intervals. A current Microfrac testing interpretation is compared and validated to a customary DFIT analysis and the new PVT sampling capability of a wireline tester fractured interval is demonstrated. Presenter’s Bio: Neil Stegent is a Technology Manager in the Halliburton Production Enhancement Technical Services Group. He is a registered professional engineer and has worked almost 38 years for Halliburton. Neil has vast field experience implementing fracture theory into practice and has taught various courses in completion optimization. He has worked most of his career focused on low permeability reservoirs and unconventional source rock. He has written numerous technical papers and holds multiple patents.

/////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////// Title: MicroFrac Testing in High Temperature (HT) Unconventional Wells Author: Javier Franquet; Dee Moronkeji (Baker Hughes, a GE company), Amie Hows (Shell) Abstract: Objectives/Scope: Understanding the geomechanical rock properties and in-situ stresses in unconventional plays is essential for optimizing completions and de-risking potential Health, Safety, and Environment (HSE) hazards. Model-based approaches are primarily relied on to characterize the mechanical rock properties and stresses from well logs. However, these models should be validated and calibrated with measurements to ensure that the proper models are being employed. The objective of the MicroFrac testing was to measure the fracture initiation, propagation and closure pressure to constrain the minimum horizontal stress (SHmin) in various intervals in the Bossier/Haynesville shale formations on a vertical pilot hole located in North Louisiana. The top of the Upper Bossier was expected at 10,258 ft. deep while the top of the Haynesville shale was predicted at 12,216 ft. deep, the maximum temperature in this well during the MicroFrac testing was 335oF (168oC). Methods, Procedures, Process: Due to the high temperature in this well, the MicroFrac tests were performed using a high temperature wireline-deployed straddle packer testing tool (HTWSPT). The HTWSPT tool can sustain up to 375°F (190oC) temperature and a pressure of 25 kpsi with the inflatable straddle packers which are designed for OBM and high temperature. This inflatable straddle packer was also modified with 5-inch exposure on each end to minimize the risk of getting stuck due to packer deformation after microfracturing. The straddle packer MicroFrac assessment consists of estimating the formation breakdown under downhole conditions and comparing with the maximum pressure between the packers allowed by the HTWSPT tool. The maximum differential pressure allowed by the HTWSPT tool depends on the hydrostatic pressure and borehole diameter. The formation breakdown was estimated from the overburden stress, lateral tectonic stresses, pore pressure, and rock tensile strength. The overburden stress was calculated by integrating the formation density log from an offset well in the same field and estimating the average rock density of the shallow formations from 2,000 ft deep to

surface (2.1 g/cc). The estimated value of overburden stress was ~1.07 psi/ft (24.422 kPa/m). The pore pressure in the Bossier - Haynesville shale was estimated around 0.76 - 0.78 psi/ft. Results, Observations, Conclusions: A total of nine (9) stations where tested for microfracturing in this well, with four (4) of the testing intervals achieving formation breakdown and repeated fracture re-opening cycles and five (5) testing intervals not inducing tensile failure at maximum differential pressure capability of the straddle packer module, leaving these intervals as mini-formation integrity tests. The maximum absolute pressure between the packers achieved by the HTWSPT tool to create a hydraulically induced fracture was 14,498 psi at 12,370 ft MD with 3898 psi of differential pressure. The four successful microfrac tests from this study indicate variability in the vertical profile of Shmin. The Shmin gradient was interpreted to vary from 0.95 – 0.99 psi.ft, with an average uncertainty of ±0.04 psi/ft. Another observation was that the difference between formation breakdown and fracture reopening-propagation pressures varied from about 1200 to 2800 psi. The magnitude of these values may indicate a difference in rock tensile strength or may be related to the presence or absence of pre-existing fractures in the test interval. Novel/Additive Information: The wireline straddle packer has the ability to do multiple testing depth under high temperature and pressure, making it useful in getting reliable stress test in HPHT wells. Similarly the tensile strength of a rock formation is shown to have an effect on variation of the difference between breakdown and reopening pressure. This talk will also discuss the capabilities of the HTWSPT to make the measurements at high temperature and the changes to the tool since the testing discussed in this talk as a result of lessons learnt to better control the flowrate to estimate the closure pressure. Presenter’s Bio: Amie Hows is the Team Lead of the Petrophysics and Geomechanics team in the Integrated Geoscience Research Program for Shell International Exploration and Production. She is a Petrophysicist with a background in Geomechanics, having earned a PhD at Stanford University under the direction of Mark Zoback. She has 10 years of experience in Shell, including a broadening assignment in Petroleum Economics and Decision Analysis. //////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////// Title: Nano-scale and Molecular Phenomena as New Unconventional Reservoir Physics Author: I. Yucel Akkutlu Abstract: It is now well-documented that the unconventional resources (shale, coal, gas hydrate) consist of pores with small volumes contributing to the storage of fluids. These volumes are not much larger than the fluid molecules they store. The nature of fluids under confinement in such small spaces is different such that they experience

significantly amplified fluid-wall molecular interactions. Consequently, various thermodynamic states may develop for the fluids and co-exist under the subsurface conditions. Further, fluid phase may change unpredictably and fluid flow could transition into several diffusion mechanisms. The presentation will discuss these basic differences in behavior of hydrocarbon mixtures quantitatively using atomistic modeling and molecular simulations. Compared to the classical hydrocarbon fluids, the behavior is different due to pore-wall dominated inter-molecular forces, mainly London dispersion and permanent dipole-dipole forces. The discussion will be tied to methane dissolution in water and to oil/gas recovery limits from kerogen, an important material constituent of source rocks. The molecular forces also play a significant role on fluid transport and could lead to potential non-Darcian flow effects. Osmosis of the injected water molecules leads to swelling of the clays in shale reservoirs and create a permeability skin near the fractures. During production, apparent gas permeability of the organic-rich shale and coal could experience non-Darcian (molecular transport) effects. These effects will be introduced using molecular simulations and laboratory measurements with core plugs under stress. The presentation will be concluded with a demonstration of the impact of the fracture skin and non-Darcian effects on the hydrocarbon reserves using a new-generation reservoir flow simulation models. Presenter’s Bio: I. Yucel Akkutlu is Flotek Industries Inc. Career Development Professor in the Harold Vance Department of Petroleum Engineering at Texas A&M University. He is a College of Engineering William Keeler Faculty Fellow. He is a chemical engineer and holds Ph.D. in petroleum engineering from the University of Southern California. His main research interest is fluid flow, transport and reactions in porous media. Akkutlu served as the executive editor of the SPE Journal, 2012-2015. He received 2016 Texas A&M University Distinguished Achievement Award, 2015 AIME Rossiter W. Raymond Memorial Award. He was 2014-2015 SPE Distinguished Lecturer.

//////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////////// Title: Measurement and Monitoring of Formation Pressure in Unconventional Reservoirs

Author: Dr. Thomas Blasingame Abstract: Points of Discussion:

Value proposition of the measurement of reservoir pressure in unconventional reservoirs?

— Ability to characterize reservoir performance without wellbore phase segregation effects.

— Ability to diagnose offset behavior (i.e., "well-to-well fracture interaction" or "frac-hits").

— Ability to diagnose production interference via hydraulic fracture and/or natural fractures, faults, etc.

Influence of uncertainties in reservoir pressure measurements? — Wellbore phase segregation can render extreme bias in surface

pressure measurements (particularly during shut-ins). — Other effects on surface pressures (temperature compensation,

surface operations, poor/infrequent measurements, etc.) — Location of pressure/temperature measurements (e.g., at the wellhead,

"before the curve" in wellbore, etc.) — Mechanical issues (e.g., downhole gauges not properly set/latched,

leaks, chemical injection systems, etc.)

Implications of errors and inconsistencies of reservoir pressure measurements? — (inconsistencies) Surface pressure measurements can be greatly

influenced/biased by operational practices. — (inconsistencies) Downhole measurements are less affected by

operational practices, but can has some bias (e.g., choke changes). — (errors) Generally due to gauge failure (rare) or gauge losing

calibration (uncommon, but it does happen).

Insight in pressure behavior and the need to continuously monitor reservoir pressures.

— Surface pressures.

Even with stated inconsistencies, surface pressures are an absolute necessity for operations and choke management.

Surface pressures can be converted to bottomhole conditions, but the scale of uncertainty may bias analysis/interpretation.

— Downhole pressures.

An opinion, but the clarity and resolution of measured bottomhole pressures make these data absolutely essential.

Downhole pressures represent the "ground truth" (or as close as we will ever have) to the in-situ reservoir pressure.

How do we live without a classic reservoir pressure measurement today? — Limits analysis to so-called "decline curve analysis" (or DCA), which

only considers time-rate behavior (to yield EUR). — Limits understanding of reservoir phase behavior (i.e., the state of the

fluids), particularly in liquids-rich systems.

— Limits understanding of the in-situ flow behavior, there is really no way to characterize even a proxy for permeability.

Summary The purpose of this invited presentation is to provide a reservoir engineering perspective to the uses of measured pressures for the diagnosis, analysis, and modeling of reservoir performance behavior. The essential message is that continuously measured bottomhole pressures are necessary in terms of the clarity and resolution of these data — particularly for choke management (early-time behavior) and for longer-term analyses of time-rate-pressure performance (known as "Rate Transient Analysis" (or RTA)) as well as for the diagnostic analysis of pressure buildup data. Presenter’s Bio: Tom Blasingame is a Professor and is the holder of the Robert L. Whiting Professorship in the Department of Petroleum Engineering at Texas A&M University in College Station Texas. He holds B.S., M.S., and Ph.D. degrees from Texas A&M University — all in Petroleum Engineering. In teaching and research activities Blasingame focuses on petrophysics, reservoir engineering, analysis/interpretation of well performance, unconventional resources, and technical mathematics. Blasingame's research efforts deal with topics in applied reservoir engineering, reservoir modeling, and production engineering. Blasingame has made several contributions to the petroleum literature in well test analysis, analysis of production data, evaluation of low/ultra-low permeability reservoirs, and general reservoir engineering (e.g., hydrocarbon phase behavior, natural gas engineering, inflow performance relations, material balance methods, and field studies). To date (February 2018), Blasingame has graduated 66 M.S. (thesis), 34 M.Eng. (report, non-thesis), and 13 Ph.D. students, and he has performed several major field studies involving geology, petrophysics, and engineering tasks. Blasingame is a member of the Society of Petroleum Engineers (SPE), the Society for Exploration Geophysicists (SEG) and the American Association of Petroleum Geologists (AAPG). Blasingame is a Distinguished Member of the Society of Petroleum Engineers (2000) and he is a recipient of the SPE Distinguished Service Award (2005), the SPE Uren Award (for technology contributions before age 45) (2006), the SPE Lucas Medal (SPE's preeminent technical award) (2012), the SPE DeGolyer Distinguished Service Medal (2013), the SPE Distinguished Achievement Award for Petroleum Engineering Faculty (2014), and SPE Honorary Membership (2015). Blasingame has served as an SPE Distinguished Lecturer (2005-2006) and is the SPE Technical Director for Reservoir Description and Dynamics (2015-2018). Blasingame has prepared approximately 150 technical articles; and he has chaired numerous technical committees and technical meetings. Blasingame also served as Assistant Department Head (Graduate Programs) for the Department of Petroleum Engineering at Texas A&M from 1997 to 2003, and Blasingame has been recognized with several teaching and service awards from Texas A&M University.