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This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199164, “Applied Learnings in Reservoir Simulation of Unconventional Plays,” by Raphael Altman, SPE, Roberto Tineo, SPE, and Anup Viswanathan, SPE, Schlumberger, et al., prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, Bogota, Colombia, 17-19 March. The paper has not been peer reviewed. Reservoir simulation is valuable in understanding dynamics of unconventional reservoirs. Applications include estimating long-term production behavior, enhancing well-spacing and pad-modeling efficiency, optimizing completion and stimulation of horizontal wells, and understanding production drivers that cause differences in productivity between wells. In the complete paper, the authors revisit fundamental concepts of reservoir simulation in unconventional reservoirs and summarize several examples that form part of an archive of lessons learned. Reservoir Simulation Applications in Unconventionals Reservoir simulation plays an important role in many stages of unconventional reservoir field development. In the initial pilot phase, a calibrated reservoir simulation model can provide an indication of estimated ultimate recovery (EUR), which is advantageous given few wells with short production time. EUR evaluation with incorporated uncertainties is a key variable in asset evaluation and investment decisions. During the ramp and development phases, reservoir simulation aids completion optimization by providing a link between completion parameters, such as cluster spacing and stimulation pumping parameters, and a well’s production. Extending this idea further, the integrated nature of reservoir simulation enables identification of production drivers and understanding of why wells are producing differently. During the mature stages of unconventional reservoir development, well spacing and hydraulic fracture and pressure interference, together with refracturing, require advanced modeling techniques that can include a combination of hydraulic fracture simulation, 3D stress simulations, and advanced reservoir simulation. Reservoir Simulation Modeling in Unconventionals Unconventional reservoirs are heterogeneous across multiple scales and exhibit variations in production performance across wells. The production variation is influenced by a large variation in production drivers that simultaneously affect the production. Examples of these drivers include reservoir properties such as hydrocarbon-filled porosity, moveable hydrocarbons, matrix permeability, relative permeability and pressure/volume/temperature, completion properties such as stress-state and natural fractures, and stimulation (pumping) parameters. Reservoir simulation constitutes one of the best tools to understand the dominant production drivers because of the multidisciplinary data required to build simulation models for unconventional reservoirs. Because of the orders of magnitude of difference in matrix permeability between conventional and unconventional reservoirs, pressure gradients from the sandface to the formation (pressure drawdowns) are larger in unconventional reservoirs and drainage radii are more likely to be smaller. Therefore, in the case of shale reservoirs, single-well models usually suffice except for the case of multiwell pads. Very fine grid cells (on the order of inches to a few feet) are used close to, and immediately surrounding, the perforation clusters, whereas in conventional reservoirs, coarser grid cells are used, especially in full-field models, even with local grid refinements.
Reservoir simulation is valuable in understanding dynamics of unconventional reservoirs. Applications include estimating long-term production behavior, enhancing well-spacing and pad-modeling efficiency, optimizing completion and stimulation of horizontal wells, and understanding production drivers that cause differences in productivity between wells. In the complete paper, the authors revisit fundamental concepts of reservoir simulation in unconventional reservoirs and summarize several examples that form part of an archive of lessons learned. Reservoir simulation plays an important role in many stages of unconventional reservoir field development. In the initial pilot phase, a calibrated reservoir simulation model can provide an indication of estimated ultimate recovery (EUR), which is advantageous given few wells with short production time.
Mitra, Abhijit (MetaRock laboratories) | Kessler, James (Occidental petroleum Corporation) | Govindarajan, Sudarshan (MetaRock laboratories) | Gokaraju, Deepak (MetaRock laboratories) | Thombare, Akshay (MetaRock laboratories) | Guedez, Andreina (MetaRock laboratories) | Aldin, Munir (MetaRock laboratories)
The magnitude of elastic anisotropy in shale is a function of composition, texture, and fabric. Rock components such as mineralogy, organic content, clay mineral orientation, alignment of matrix pore and intraparticle kerogen pores, as well as the distribution of cracks, fractures, and other discontinuities can influence anisotropy. Elastic anisotropy has a significant impact on seismic waveform interpretation, time-depth models, and stress characterization used in drilling and well completion design. Anisotropy can be estimated explicitly from core measurements but the time and budgetary requirements to conduct extensive laboratory measurements are usually prohibitive in an operating environment. Existing models aimed at characterizing anisotropy from log data involve some assumptions that may not be realistic in every formation or lithology type. We aim to predict anisotropy from log data as a function of lithotype defined primarily by mineralogy, organic content, and porosity.
This paper presents a workflow to identify lithotypes based on mineralogy, organic content, and porosity in core data from a single well and then predict elastic anisotropy for each lithotype away from the cored interval and in other wells. The workflow employs a multi-disciplinary experimental program using geology, engineering, and data analytics techniques to interpret data from core samples and log data obtained from a well in the Permian basin. First, we derive the relationship between stiffness anisotropy and lithotypes defined in core. Second, we derive the relationship between lithotype and electrofacies from log data using machine learning techniques like principal component and clustering algorithms. We then apply the predictive models to estimate anisotropy for each lithotype and test the predictive capability in the source well.
Analyses of laboratory measurements reveal that anisotropy is not significantly influenced by any single mineralogical constituent, volume of organic material, or porosity. However, a multiple linear regression model that utilizes all three of those constituents measured from core is successful in predicting anisotropy for lithotypes identified from machine learning techniques. There is good agreement between measured and modeled anisotropy when applied as an upscaling tool using well log data. Further work will test the predictability of the model in a blind test well by comparing modeled results with core and log data that are independent of this analysis.
This paper successfully applies a combination of traditional geological and engineering applications with new machine learning techniques to characterize lithotypes and predict rock properties such as elastic anisotropy. The technique avoids the assumptions used in existing models to characterize anisotropy and provides the foundational workflow that can be utilized to predict other rock properties for a variety of applications in the unconventional oilfield.
Cook, David (BHP Billiton Petroleum) | Downing, Kirsty (BHP Billiton Petroleum) | Bayer, Sebastian (BHP Billiton Petroleum) | Watkins, Hunter (BHP Billiton Petroleum) | Sun Chee Fore, Vanon (BHP Billiton Petroleum) | Stansberry, Marcus (BHP Billiton Petroleum) | Saksena, Saurabh (BHP Billiton Petroleum) | Peck, Doug (BHP Billiton Petroleum)
Abstract The Eagle Ford Shale is recognized as the largest oil and gas development in the world, based on capital investment (Wood Mackenzie 2012). Development typically consists of horizontal wells stimulated with multiple hydraulic fracture stages. Almost $30 billion will be spent developing the play in 2013, and optimizing the completion design and spacing of these wells can result in large rewards for the companies involved. This paper presents a pragmatic integrated workflow, used to optimize development and guide critical development decisions in the Black Hawk field, Eagle Ford Shale. Geoscientists, reservoir, and completion engineers worked collaboratively to identify the optimal completion designs and well spacings for development focus areas. Multiple simplistic simulation models were history matched to existing production wells. Wide uncertainty exists in many key reservoir and completion parameters. Using stochastic realizations from ranges of key properties, uncertainty was reduced using the history matching process. The resulting calibrated reservoir scenarios formed the basis of optimization studies for development drilling and down spacing. Completion design parameters, including fracture stage length, perforation clusters per stage and landing point for the lateral, were evaluated in hydraulic fracture models. The resulting fracture geometries were simulated and the optimum completion design, and well spacing determined for each area. The optimal development was shown to vary by region, due to changing reservoir, fluid and geomechanical properties. The use of multiple subsurface realizations, spanning an appropriate range of uncertainty, was critical to the success of this study. Economic analysis across a range of potential outcomes enabled robust development decisions to be made. As a result of this work, field trials to test proposed changes to the completion have been initiated, and development drilling plans updated to reflect the optimal well spacing for each lease.
Abstract Appraisal wells in unconventional, very low permeability, resource plays require large hydraulic fracture treatments to assess economic viability. In many cases, drainage area and hydrocarbon recovery are defined by the areal extent and effectiveness of the hydraulic fracture treatment. To increase the drainage area and recovery per well, multiple hydraulic fracture treatments in horizontal and vertical wells are now common, resulting in more complex and expensive completions. Therefore, appraising the completion and hydraulic fracture treatment are just as important as appraising the reservoir. Unlike conventional reservoirs, the complexity and heterogeneity of unconventional resources can make reliable reservoir characterization difficult, which can result in significant uncertainty when evaluating appraisal well performance. Therefore, applying the appropriate technologies for unconventional reservoirs and a holistic approach are essential to properly separate reservoir quality from completion effectiveness. This paper details technologies and workflows that are essential to the reliable appraisal of unconventional resources, with an emphasis on appraising resources outside of North America. Due to the high cost of appraisal wells in most environments outside North America, operators must assess the viability of unconventional resources using as few wells as possible. The North American model of assessing unconventional reservoirs by drilling and completing a large number of wells may not be economically feasible in areas with insufficient hydraulic fracturing, drilling, and completion infrastructure. Due to the variability of both hydraulic fracture growth and reservoir characteristics in unconventional reservoirs, properly assessing new plays and subsequently optimizing fracture treatments and completions has historically been a ?trial and error? process requiring a large number of wells and significant capital risk. However, efficient evaluation of stimulation treatments and completions is now possible by combining microseismic mapping and other hydraulic fracture diagnostics with advanced logs, specialized core tests, 3D seismic, and newly developed ?unconventional? hydraulic fracture models. This holistic approach reduces the number of wells required to assess the economic viability of unconventional resources and reliably separates reservoir quality from completion effectiveness. The application of these unconventional-reservoir-specific technologies, newly developed hydraulic fracture models, and specialized workflows are illustrated using examples from North America. Introduction There are significant differences between the evaluation of unconventional resources and conventional plays. The exploitation of unconventional reservoirs requires large hydraulic fracture stimulations that contact a huge reservoir surface area and effectively connect this surface area back to the wellbore. Contacting a large reservoir surface area significantly increases hydrocarbon production rates and recovery, enabling economic development. In fact, the effectiveness of the hydraulic fracture treatment will control both well productivity and drainage area in unconventional reservoirs (Cipolla et al., 2008a). The very low matrix permeability of these reservoirs necessitates a large number of wells to effectively develop the resource base. In recent years the application of horizontal drilling has dominated unconventional reservoir development, accessing much more reservoir volume than vertical wells and reducing the number of wells required to develop the resource. The combination of multi-stage hydraulic fracture stimulation and horizontal drilling has enabled exploitation of vast North American shale resources (Arthur et al. 2008; Jenkins and Boyer 2008) and improved the economics of developing some tight gas resources (Baihly et al. 2009). However, the application of horizontal drilling and the need to perform multiple hydraulic fracture treatments adds to the complexity of the completion and results in much more uncertainty when evaluating well performance and optimizing stimulation designs and completion strategies.