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Summary Modern hydraulic-fracture treatments are designed by use of fracture simulators that require formation-related inputs, such as in-situ stresses and rock mechanical properties, to optimize stimulation designs for targeted reservoir zones. Log-derived stress and mechanical properties that are properly calibrated with injection data provide critical descriptions of variations in different lithologies at varying depths. From a practical standpoint, however, most of the hydraulic-fracturing simulators that are currently used for treatment design use only a limited portion of a geologic-based rock-mechanical-property characterization, thus resulting in outputs that may not completely align with observed outcomes from a fracturing treatment. By use of examples from hydraulic-fracture stimulations of coals in a complex but well-characterized stress environment in Surat Basin of eastern Australia, we obtain the reservoir-rock-related input parameters that are important for the design of hydraulic fractures and also identify those that are not essential. To understand the effect on improving future fracture-stimulation designs, the authors present work flows for pressure-history matching of treatments and subsequent comparison of corresponding geometries with external measurements, such as microseismic (MS) surveys, to calibrate geomechanical models. The paper presents examples discussing synergies, discrepancies, and gaps that currently exist between “geologic” geomechanical concepts in contrast to the geomechanical descriptions and concepts that are used and implemented in hydraulic-fracturing stimulations. Ultimately it remains paramount to constrain as many critical variables as realistically and as uniquely as possible. Significant emphasis is placed on reservoir-specific pretreatment data acquisition and post-treatment analysis. Some of the obvious differences observed between the measured and fracture-model-derived geometries are also presented in the paper, highlighting the areas in fracture modeling where significant improvement is needed. The approach presented in this paper can be used to refine hydraulic-fracture-treatment designs in similar complex reservoirs worldwide.
Abstract The Walloons coal measures located in Surat Basin (eastern Australia) is a well-known coal seam gas play that has been under production for several years. The well completion in this play is primarily driven by coal permeability which varies from 1 Darcy or more in regions with significant natural fractures to less than 1md in areas with underdeveloped cleat networks. For an economic development of the latter, fracturing treatment designs that effectively stimulate numerous and often thin coals seams, and enhance inter-seam connectivity, are a clear choice. Fracture stimulation of Surat basin coals however has its own challenges given their unique geologic and geomechanical features that include (a) low net to gross ratio of ~0.1 in nearly 300 m (984.3 ft) of gross interval, (b) on average 60 seams per well ranging from 0.4 m to 3 m in thickness, (c) non-gas bearing and reactive interburden, and (d) stress regimes that vary as a function of depth. To address these challenges, low rate, low viscosity, and high proppant concentration coiled tubing (CT) conveyed pinpoint stimulation methods were introduced basin-wide after successful technology pilots in 2015 (Pandey and Flottmann 2015). This novel stimulation technique led to noticeable improvements in the well performance, but also highlighted the areas that could be improved – especially stage spacing and standoff, perforation strategy, and number of stages, all aimed at maximizing coal coverage during well stimulation. This paper summarizes the findings from a 6-well multi-stage stimulation pilot aimed at studying fracture geometries to improve standoff efficiency and maximizing coal connectivity amongst various coal seams of Walloons coal package. In the design matrix that targeted shallow (300 to 600 m) gas-bearing coal seams, the stimulation treatments varied in volume, injection rate, proppant concentration, fluid type, perforation spacing, and standoff between adjacent stages. Treatment designs were simulated using a field-data calibrated, log-based stress model. After necessary adjustments in the field, the treatments were pumped down the CT at injection rates ranging from 12 to 16 bbl/min (0.032 to 0.042 m/s). Post-stimulation modeling and history-matching using numerical simulators showed the dependence of fracture growth not only on pumping parameters, but also on depth. Shallower stages showed a strong propensity of limited growth which was corroborated by additional field measurements and previous work in the field (Kirk-Burnnand et al. 2015). These and other such observations led to revision of early guidelines on standoff and was considered a major step that now enabled a cost-effective inclusion of additional coal seams in the stimulation program. The learnings from the pilot study were implemented on development wells and can potentially also serve as a template for similar pinpoint completions worldwide.
Abstract Modern hydraulic fracture treatments rely heavily on the implementation of formation property details such as in-situ stresses and rock mechanical properties, in order to optimize stimulation designs for specific reservoir targets. Log derived strain and strength calibrated in-situ properties provide critical description of stress variations in different lithologies and at varying depths. From a practical standpoint however, most of the hydraulic fracture simulators that are used for fracturing treatment design purposes today can accommodate only a limited portion of a geologic-based rock mechanical property characterization which targets optimal data integration thus resulting in complexity. By using examples from hydraulic fracture stimulations of coals in a complex but well characterized stress environment (Surat Basin, Eastern Australia) we distil out the reservoir rock related input parameters that are determinants of hydraulic fracture designs and identify those that are not immediately used. In order to understand the impact on improving future fracture stimulation designs, the authors present workflows such as pressure history matching of fracture stimulation treatments and the calibration process of key rock mechanical parameters such as Poisson's ratio, Young's modulus, and fracture toughness. The authors also present examples to discuss synergies, discrepancies and gaps that currently exist between ‘geologic’ geomechanical concepts (i.e. variations in the geometry and magnitude of stress tensors and their interaction with pre-existing anisotropies) in contrast to the geomechanical descriptions and concepts that are used and implemented in hydraulic fracturing stimulations. In the absence of a unifying hydraulic fracture design that honors well established geologic complexity, various scenarios that allow assessing the criticality, usefulness and weighting of geologic/mechanical property input parameters that reflect critical reservoir complexity, whilst maintaining applicability to hydraulic fracturing theory, are presented in the paper. Ultimately it remains paramount to constrain as many critical variables as realistically and uniquely possible. Significant emphasis is placed on reservoir-specific pre-job data acquisition and post-job analysis. The approach presented in this paper can be used to refine hydraulic fracture treatment designs in similar complex reservoirs worldwide.
Flottmann, Thomas (Origin Energy) | Pandey, Vibhas (ConocoPhillips) | Ganpule, Sameer (Origin Energy) | Kirk-Burnnand, Elliot (Origin Energy) | Zadmehr, Massoud (Origin Energy) | Simms, Nick (Origin Energy) | Jenkinson, Jeslie George (Origin Energy) | Renwick-Cooke, Tristan (Origin Energy) | Tarenzi, Marco (Origin Energy) | Mishra, Ashok (ConocoPhillips)
Abstract Walloons Coals of the Surat Basin, Queensland (Australia) contain world class Coal Seam Gas (CSG) plays, where permeability varies from high (>1Darcy), due to Gaussian curvature-related natural fracture connectivity, to low (<1mD) due to unidirectional fracture-systems attributed to regional unidirectional flexure. The low permeability Walloons Coals require stimulation to unlock their gas resources. This contribution describes the design evolution of stimulation concepts in the Surat Basin in context of five key subsurface drivers Coal net to gross: Surat Basin coals contain 30 coal seams with a cumulative thickness of 20-35m in a gross rock column of >300m Permeability of coals requiring stimulation for economic flow rates varies from <1mD - ~30mD Varying stress regimes, both vertically and laterally Ductile rock properties in Walloons coal reservoirs Productivity Index drop (PI drop) can occur when (incompressible) water is replaced by (compressible) gas during coal dewatering Early stimulation treatments in Surat Basin (pre-2010) followed ‘standard’ high rate water/sand designs adapted from the shale industry. However, high treating pressure and rates resulted in several instances of casing shear (Johnson et al. 2003) particularly at depths associated with stress regime transitions. Subsequent designs (2010-12) repeated water fracs albeit including ample diagnostics (Johnson et al 2010; Flottmann et al 2013), showing that water fracs appear to be ineffective in stimulating Walloons Coals. Design optimizations in 2015 (Kirk-Burnnand et al. 2015) based on extensive modeling work (Pandey and Flottmann 2015), identified low rate gel fracs as optimal to stimulate rocks with ‘ductile’ Walloons-specific coal properties. However, treatment rates were limited to optimize height growth, both to connect coals and to avoid height growth into non-reservoir. Initial production data indicated a drop in well productivity in some fracture stimulated coals (Busetti et al. 2017). Consequently, stimulation designs were modified in late 2016 to account for such productivity drops while maximizing the fluid recovery. Early time post stimulation drawdown strategy was also field-tested to mitigate loss of well productivity due to excessive drawdown which could cause partial or full fracture closure (especially near the wellbore region), and lead to loss of communication between reservoir and well. Sub-surface drivers identified in tight Walloons Coals control the effectiveness of any stimulation option deployed. These drivers influence the effectiveness of stimulation in multiple ways. First, these drivers can lead to a sub-optimal connectivity between well and reservoir resulting in poor productivity and marginal recovery. Second, the drivers may influence an operator towards expensive stimulation options which may provide better well to reservoir connectivity but diminish the economic value due to the high costs involved. Hence the inclusion of sub-surface drivers in selecting stimulation design is paramount as demonstrated in this paper.
Abstract Objective Knowledge of fracture entry pressures or the formation face pressures during Acid Fracturing treatments can help in evaluating the effectiveness of the stimulation treatment in dynamic mode and can also enable and improve real-time decisions during the execution of treatment. In this paper, details of the methods and tools employed to generate formation face pressures in real-time mode with the help of live bottomhole pressure data, is discussed in detail. Methods, Procedures, Process The majority of the horizontal wells considered for this study were drilled and completed in the North Sea with permanent bottomhole pressure gauges that enabled constant monitoring of well pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, type of fluid, wellbore description, gauge depth, and wellbore deviation, along with bottomhole pressures to generate formation face pressures just outside the casing at active perforation depth. The tool carries out the calculations as the treatment is being pumped thus providing a dynamic array of several important parameters and can also evaluate the treatment after it has been executed. Results, Observations, Conclusions Acid fracturing treatments combine the basic principles of hydraulic fracturing and acid reaction kinetics to stimulate acid soluble formations. It is customary to start the treatment with a high viscosity pad to generate a fracture geometry and follow it up with acid to react with the walls of the fracture and etch it differentially. The non-uniform etching action of the acid creates an uneven surface on fracture walls that provides the requisite fracture conductivity which is key to enhancing the well performance. The effectiveness of a treatment schedule can be ascertained by determining and analyzing the pressure behavior during the injection process. Several acid fracture treatments were analyzed using the tool and led to important conclusions related to fracture propagation modes, acid exposure times and effectiveness of given acid types. The results had a direct influence on modification of treatment designs and pump schedules to optimize treatment outcomes. Novel Ideas The knowledge of formation face pressures is critical to the success of hydraulic fracturing treatments, especially in multi-stage and multiple perforation cluster type horizontal well completions. The tool developed in the study helps generate information that predicts pressures at fracture entry in real-time mode.