This is the first column of my 9-month stint as Executive Editor ad interim of the reservoir evaluation section of SPE Res Eval & Eng. I’d like to begin by thanking my predecessor, Francesca Verga, for her dedicated service as Executive Editor.
I am currently senior research scientist at The University of Texas (UT) Bureau of Economic Geology, where I have been employed for more than 30 years. My initial work at UT was geologic research in support of experiments in hydraulic fracture design and diagnostics. I’ve led research projects related to unconventionals and fractured reservoirs. I supervise graduate students in natural and hydraulic fracture research in a cooperative program between the Cockrell School of Engineering and Jackson School of Geosicences. I’ve been involved with SPE for many years. I was a member of the Technical Program Committee for the SPE Rocky Mountain Regional and Low-Permeability Reservoir Symposium in 1992 – 1993 and I served on the SPE Forum Series Steering Committee on Future Challenges in Carbonate Resource Development in 2004 – 2005. I was an SPE Distinguished Lecturer in 2003 – 2004. Before taking on the interim Executive Editor role, I was Technical Editor for SPE Formation Evaluation from 1996 to 1998, and of SPE Res Eval & Eng from 1998 to 2012. I’ve served as Associate Editor of SPE Res Eval & Eng since 2012. I also co-chaired the 1994 North American Rock Mechanics Symposium and have served on National Research Council committees on advanced drilling technologies and on underground science and engineering. I hold a BS degree from Tufts University and a PhD from the University of Illinois, both in geology.
This issue of SPE Res Eval & Eng brings you 14 papers covering topics of current interest in the industry. Seven papers explore quantitative characterization of the controls on production response over a wide range of scales and with a variety of techniques. Two papers focus on the key topic of improved measurements. Another two papers deal with unconventionals and uncertainty. The final three papers are related to heavy oil, enhanced oil recovery (EOR) and waterflooding.
Integration of Pressure-Transient Data in Modeling Tengiz Field, Kazakhstan—A New Way To Characterize Fractured Reservoirs describes a work flow to integrate pressure transient data collected from single-well buildup tests in numerical reservoir simulation models for a fracture/matrix system. The procedure starts with a numerical simulation model, either a discrete fracture/matrix model or a dual-porosity, dual-permeability model, and follows with the analysis of a numerically generated buildup test to calculate the fracture spacing and shape factor of the model. A novel aspect of the work is the quantitative use of the correlations between pressure-transient-analysis results and the representative values of the input parameters in a numerical model to reduce the number of simulation iterations. Before field application, the numerical-simulation results were validated against analytical pressure-transient solutions for a dual-porosity system. Applications are illustrated by a sector model in the southeast region of Tengiz Field, Kazakstan, an example in which single-well and multiple-well-transient data, production logging, and image-log data are all available. The study shows how effective integration of dynamic and static data can impact reservoir management. The paper is also a great example of the progress that can be achieved by a potent cross-disciplinary team.
A Quantitative Approach To Characterize Porosity Structure From Borehole Electrical Images and Its Application in a Carbonate Reservoir in the Tazhong Area, Tarim Basin describes porosity in the Ordovician condensate/gas field in the Tazhong area, Tarim Basin, the first discovered Ordovician carbonate reef field in China. Porosity structure was quantified from image logs. The paper describes how to measure the spectrum shape of the porosity from logs by using the length between the peak of primary porosity and the right-most peak of secondary porosity, marking the heterogeneity of pore structure. The second indicator reflects shape changes of the right part of the porosity spectrum, and measures the proportion of secondary porosity.
Comparison of rock properties and production performance and hydraulic-fracturing flowback provides insight into major geologic controls that differentiate tight gas sandstones. Geologic Controls on Gas Production and Hydraulic-Fracturing Flowback in Tight Gas Sandstones of the Late Jurassic Monteith Formation, Deep Basin, Alberta, Canada identifies key geologic and engineering aspects of two important unconventional siliciclastic targets in the Western Canada Sedimentary Basin, the Monteith A and Monteith C intervals, including the nature of porosity and permeability, and their relation to petrophysical properties as qualitative indicators of storage, and flow capacities; mineralogical composition; characteristic flow units; possible relationships between sedimentary facies, mineralogy and diagenetic processes and their potential predictive value for reservoir quality, petrophysical rock properties; and the relationship of the their geologic properties, hydraulic-fracturing flow back, and gas production from individual wells.
An Integrated Work Flow for a Comprehensive Evaluation of Thin, Silty Hydrocarbon-Reservoir Sequences presents a work flow and two field examples to show how to identify low-resistivity pay in thinly laminated sandstones with silty and/or shaly layer. A key step is a mini-drill-stem test using a wireline formation tester to determine fluid type and productivity of each individual layer. The work flow includes data from gas-while-drilling, conventional logging, and nuclear-magnetic-resonance (NMR) logging for picking intervals for further examination by wireline formation tester.
A concern regarding the deployment of hydraulic fracturing is the reactivation of pre-existing faults and possibility of triggering low-magnitude seismic events that might be felt at the surface. Analysis of Stress-Field Variations Expected on Subsurface Faults and Discontinuities in the Vicinity of Hydraulic Fracturing describes a method call slip-tendency analysis that evaluates local stability and possibility of fault reactivation under the influence of net pressure and in situ stress fields. Numerical and analytical solutions confirm the presence of both unstable and stable regions around the pressurized fractures. Although general patterns of slip-tendency distributions around pressurized fractures are similar under different in-situ stress conditions, the normal faulting environment has larger variations in slip-tendency than the strike-slip faulting environment during hydraulic-fracturing stimulation. Unstable regions identified in numerical models may be regions of improved permeability.
The goal of History Matching and Rate Forecasting in Unconventional Oil Reservoirs With an Approximate Analytical Solution to the Double-Porosity Model was to develop a rate-vs.-time relationship to predict realistic future performance from hydraulically fractured wells in unconventional formations. This paper presents a new approximate analytical solution to the double-porosity model in real-time space and its use in modeling and forecasting production from unconventional oil reservoirs. The solution is valid across all time domains; that is, it is a continuous function that is valid during the transient and late-time flow from the fracture and matrix. The solution is validated against numerical simulation, and the paper presents example applications to field data.
Analyzing well performance is a complex process that increases in difficulty when multiple reservoir-drive mechanisms are in play in the same reservoir. Understanding Variable Well Performance in a Chalk Reservoir explores an overpressured, compacting chalk reservoir with high porosity and high oil saturation at initial conditions. Using the history of ValHall Field, Norway, to illuminate the various drive mechanisms experienced, the study proposes a work flow for highly complex reservoirs with different rock-mechanical properties, drive mechanisms, production scheduling, and field-development strategies.
Improved Assessment of Interconnected Porosity in Multiple-Porosity Rocks by Use of Nanoparticle Contrast Agents and Nuclear-Magnetic-Resonance Relaxation Measurements describes the use of supermagnetic iron oxide nanoparticles (SPION) as contrast agents injected into rock samples having a multiporosity system. Laboratory and numerical simulations quantified their impact on NMR measurements. Results show that SPION injection improves characterization of interconnected porosity and connectivity of natural fractures in rock samples with complex pore geometry (e.g., those from carbonate and organic-rich mudrock formations). The outcomes of the paper are promising for successful application of the technique to systems containing interconnected fractures.
Successful proactive geosteering from extradeep azimuthal-resistivity measurements and new software provide early warnings and additional information to help steer the well in geologically complex reservoirs. Applied in Peregrino Field in Brazil, the device operates at lower frequencies than the shallower reading tools, has large transmitter/receiver spacings, and a depth of detection up to 25 m. Examples are presented in Extradeep-Resistivity Application in Brazil Geosteering Operations Enables Successful Well Landing from one well where the extradeep resistivity provided early warnings and additional information that helped to steer the well successfully and maximize reservoir coverage.
Uncertainty quantification of field-scale production and economics is a key factor for the successful development of unconventional resources. Integrated Field-Scale Production and Economic Evaluation Under Subsurface Uncertainty for the Pattern-Driven Development of Unconventional Resources With Analytical Superposition shows that, under certain assumptions, an analytical superposition formulation can be developed that propagates the uncertainties of production forecasts and economic evaluations generated from a sector model to full field-scale quantities. Results enable an uncertainty work flow in which single-pattern results are upscaled to accurate full field results with reliable uncertainty ranges, without the need for full field-scale simulations.
Raising the question that rapid development of shales for the production of oils and condensates may not be permitting adequate analysis of the important factors governing recovery, Factors That Control Condensate Production From Shales: Surrogate Reservoir Models and Uncertainty Analysis identifies factors that control production of condensates from low-permeability plays and develops analytical surrogate models suitable for Monte Carlo analysis. The main factors that controlled condensate recovery from ultralow-permeability reservoirs were reservoir permeability, rock, compressibility, initial condensate/gas ratio, initial reservoir pressure, and fracture spacing. In exploring condensate recovery on the basis of the uncertainty in input parameters, the study shows that quick screening and uncertainty assessment of the performance of condensates in shales is feasible.
Low-salinity waterflooding is an emerging EOR technique in which the salinity of the injected water is reduced substantially to improve oil recovery over conventional higher-salinity waterflooding. Mechanistic Modeling of Low-Salinity Waterflooding Through Coupling a Geochemical Package With a Compositional Reservoir Simulator reports a step-by-step algorithm for integrating a state of the art geochemical package, IPhreeqc, with the compositional reservoir simulator, UTCOMP. The result is a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low-salinity waterflooding.
Particle-size distribution (PSD) is a list of values that defines the relative amount of particles present according to the size in a sample. PSD is known to be a significant factor for evaluating bitumen recovery from an oilsand mine because the presence of fines (evaluated by PSD analysis) affects the hot-water-separation process and processing-plant recovery prediction and provides grade control. Presence of more fines translates into lower recovery from commercial oil-sand processing. On the basis of analysis of a field in northern Alberta, Canada, On the Use of Particle-Size-Distribution Data for Permeability Prediction finds PSD to be a critical parameter for evaluation and estimation of permeability of an oilsand reservoir. Information provided by the PSDs for permeability prediction is more significant than that inferred from a simple porosity/permeability relationship. The paper documents a methodology for accurate modeling of PSDs and provides a work flow for incorporating these data in improved understanding and modeling of permeability and its distribution.
In the field of flow in porous media, nonisothermal conditions are encountered in many applications. Analytical Solutions and Derivation of Relative Permeabilities for Water-Heavy Oil Displacement and Gas-Heavy Oil Gravity Drainage Under Non-Isothermal Conditions recounts the development of new analytical models for nonisothermal gas/heavyoil gravity drainage and water/heavy-oil displacements in round capillary tubes including the effects of a temperature gradient throughout the system. By use of the model solution for a bundle of capillaries, relative permeability curves were generated at different temperature conditions. The results showed that water/gas/heavy-oil-interface location, oil-drainage velocity, and production rate depend on the change of oil properties with temperature.
Stephen E. Laubach
Co-Executive Editor of SPE Res Eval & Eng
Laubach is a Senior Research Scientist at UT Bureau of Economic Geology. A structural geologist, his interests include fractured and unconventional reservoirs. Dr. Laubach leads the Fracture Research and Application Consortium and the Structural Diagenesis Initiative, supervises graduate student research in structural geology and structural diagenesis in the Jackson School of Geosciences. He was a member of the AAPG Executive Committee and AAPG Elected Editor from 2010-2013 and served as a Co-opted Member of the Petroleum Group Committee of the Geological Society of London from 2008 to 2012. Laubach was a Distinguished Lecturer for AAPG in 2010-2011 and Distinguished Lecturer for SPE in 2003-2004. He was a member of the Committee to Assess the Science Proposed for a Deep Underground Science and Engineering Laboratory, National Research Council, 2010-2011 and the Committee on Advanced Drilling Technologies, National Research Council, 1992-1994. Laubach served as co-Chairman of the First North American Rock Mechanics Symposium in 1994. From 2013 to 2015, he served as a Member, Council on Earth Sciences, US Department of Energy, Office of Science, and since 2015 he has served on the Council on Chemical Sciences, Geosciences and Biosciences.