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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 Fracture growth in layered formations with depth-dependent properties has been a topic of interest amongst researchers because of its critical influence on well performance. This paper revisits some of the existing height-growth models and discusses the evaluation process of a new and modified model developed after incorporating additional constraints.The net-pressure is the primary driver behind fracture propagation and the pressure distribution in the fracture plays an important role in vertical propagation, as it supplies the necessary energy for fracture advancement in the presence of opposing forces. The workflow adopted for this study included developing a preliminary model that solves a system of non-linear equations iteratively to arrive at fracture height versus net pressure mapping. The theoretical results were then compared to those available in the literature. The solution set was then extended to a 100-layer model after incorporating additional constraints using superposition techniques.The predicted outcomes were finally compared to the fracture height observations made in the field on several treatments. A reasonable agreement between model-predicted and observed height was observed when a comparison between the two was made, for most cases.The majority of these treatments were pumped in vertical wells, at low injection rates of up to 8.0 bbl/min (0.021 m/s) where net pressures were intentionally restricted to 250 psi (1.72 MPa) in order to prevent fracture rotation to the horizontal plane.The leak-off was minimal given the low permeability formations. In some cases, however, the pumping parameters and fluid imparted pressure distribution appeared to dominate. Overall, it was apparent that for a slowly advancing fracture front, which is the case in low injection rate treatments, the fracture height could be predicted with reasonable accuracy. This condition could also be met in high rate treatments pumped down multiple perforation clusters such as in horizontal wells, though fracture-height measurement may not be as straightforward as in vertical wells. The model developed under the current study is suitable for vertical wells where fracture treatments are pumped at low injection rates. The solid-mechanics solution that is presented here is independent of pumping parameters and can be readily implemented to assist in selection of critical design parameters prior to the job, with a wide range of applicability worldwide.
Summary Knowledge of fracture‐entry pressures or formation‐face pressures (FFPs) during acid‐fracturing treatments in real‐time mode can help in evaluating the effectiveness of the treatment and improve the decision‐making process during execution. In this paper, methods and tools used to generate FFPs in real‐time mode with the help of bottomhole‐pressure (BHP) data are discussed in detail. The horizontal wells selected for the study were drilled and completed in the North Sea with permanent BHP gauges that enabled constant monitoring of downhole pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, fluid type, wellbore details, and wellbore deviation, along with bottomhole‐gauge pressures, to calculate fracture‐inlet pressures just outside the casing at active perforation(s) depth. The tool performs the calculations in “live” mode during treatment execution and simultaneously generates a dynamic array of data that assists in “on‐the‐fly” evaluation and the decision‐making process. Several acid‐fracture treatments were analyzed using the tool and led to important conclusions related to fracture‐propagation modes, acid‐exposure times, and the effectiveness of given acid types. The results had a direct influence on the modification of treatment designs and pump schedules to optimize treatment outcomes.
Abstract Semi-automation of hydraulic fracturing treatment designs often necessitates the application of simplified predictive models. Such models can only incorporate a limited subset of the relevant rock mechanical properties and an approximate representation of the stress state. This paper demonstrates the fundamental influence of three-dimensional stress states on the propagation of hydraulic fractures in coal seam gas (CSG) wells, and contrasts these results with those from two-dimensional simulations conducted in a one-dimensional stress state. A three-dimensional, finite element-discrete element (FEM-DEM) model of a single well stage was developed as the basis for this study. This synthetic well was informed by case studies from the Surat Basin, Queensland, featuring varying complexity of key geomechnical factors. These include the existence of ∼30 coal seams within a gross rock column of more than 300 m, stress states that vary both laterally and vertically, ductile rock properties, and varying natural fracture densities and orientations. The developed model captures the full tensor description of stress, poroelastic-plastic modelling of the rock and coal, fully coupled fluid flow, and explicit modelling of fracturing. The stress state was parametrically defined so that normal, strike-slip and reverse faulting conditions could be imposed and the magnitude of stresses varied to capture the appropriate range of varying conditions. A single perforation cluster was then used to induce a hydraulic fracture in an isotropic medium. Hydraulic fracture propagation (and propagation complexity) is influenced significantly by differential stresses, stress orientations and relative stress magnitudes. None of these are captured in two-dimensional simulations using a one-dimensional stress characterisation which is commonly derived from one-dimensional wellbore stress models. The findings of this work clearly demonstrate the ability of fractures to turn and grow preferentially when they are not constrained to a two-dimensional plane. It also shows how the initiation of fractures (i.e. orientation to stress) impacts the propagation complexity of hydraulic fractures from the direction of maximum principal stress. In general, this paper highlights the benefit of incorporating the three-dimensionality of key geomechnical parameters when designing hydraulic fracturing stimulation treatments. Future work will incorporate greater reservoir detail (e.g. pressure-dependence, heterogeneity of stress and material properties) to further investigate fracture containment and reorientation.
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.
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 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.
Summary The Sacatosa field in west Texas was discovered in 1956. Since then, more than 1,500 wells have been drilled and completed in the main reservoir section known as the San Miguel 1. The San Miguel 1 is primarily low-permeability sandstone, with several shale layers dispersed throughout. Economic development of the field requires effective well stimulation and an active waterflood program to provide pressure maintenance. Unfortunately, the available injection water is of poor quality and can rapidly plug up pore throats with solids, resulting in significant near-wellbore formation damage. When these factors are considered, hydraulic fracturing of both injector and producer wells is a viable option for improved long-term well performance. However, because of relatively shallow depths, traditional hydraulic-fracturing practices can lead to a multiplane fracture system with a mix of horizontal and vertical components. A significant presence of horizontal fractures can be detrimental to fractured-well performance because of the low conductivities of the fractures. In producer wells, this could impair production if the reservoir is laminated and has low vertical permeability. In injectors, water-front movement and sweep efficiency would be diminished greatly. This paper discusses the steps taken to plan and develop a strategy to place vertical fractures in shallow San Miguel 1 sands. These findings can easily be extended to similar shallow-depth reservoirs worldwide. Some major modifications in completion design included changes in perforation strategy, redesign of the pump schedule, and implementation of a staged stimulation. Fracturing treatments were pumped on a total of 26 injectors and eight producers through a variety of methods, including coiled-tubing fracturing. Post-fracture analysis suggests a strong vertical-fracture component, and analysis of injectivity tests shows fracture parameters in line with design objectives. All the producers that were fracture stimulated with this technique reported higher initial production when compared with wells stimulated through the use of legacy treatment schedules.
Abstract Frac-Pack techniques were used in a recent subsea well completion campaign. The sandstones layers targeted for completion are generally present in shallow gas reservoirs with depths ranging from 2,000 to 4,500ft [609.60 to 1,371.60m] TVDSS and exhibit a varying degree of consolidation. Core data shows that deeper pay intervals predominately comprise of fine grained, poorly consolidated sandstones with good porosity development and permeabilities in the 100 to 1000+mD range. These sand layers are often separated by shales and claystones. In contrast to this, the target sandstone layers in shallower intervals mostly consist of more consolidated rock with lower permeabilities in the 5 to 50mD range. Up to eight sand intervals are targeted in each well. The subsea environment posed well completion design challenge because of the multi-layered completion strategy that was required to effectively drain several of the pay units in each well. Multi-zone, frac-pack completions consisting of isolation packers and sand control screens with separate pumping and production sleeves were used to provide sand control. An inner-string of additional isolation seals, gauges and intelligent control valves were run to provide zone specific monitoring and production control. The initial well completion work resulted in high skin values during production. Review of post-stimulation data helped in identifying the shortcomings in designs and completion procedure. As a result of this, changes were made in the completion procedures, and frac-pack designs were tailored to suit the purposes. When these changes were implemented in subsequent wells, an improvement in well performance was seen, mostly in the form of reduced skin. The paper details this evolution, including favorable modification of completion procedures, as well as, the changes in pump schedule, treatment planning, and delivery methods during the frac-pack campaign. The benefit of adopting such an approach, using the methods and techniques used in this campaign, can be applied to similar fields under development.
Frac-Pack techniques were used in a recent subsea well completion campaign. The sandstones layers targeted for completion are generally present in shallow gas reservoirs with depths ranging from 2,000 to 4,500ft [609.60 to 1,371.60m] TVDSS and exhibit a varying degree of consolidation. Core data shows that deeper pay intervals predominately comprise of fine grained, poorly consolidated sandstones with good porosity development and permeabilities in the 100 to 1000+mD range. These sand layers are often separated by shales and claystones. In contrast to this, the target sandstone layers in shallower intervals mostly consist of more consolidated rock with lower permeabilities in the 5 to 50mD range. Up to eight sand intervals are targeted in each well.
The subsea environment posed well completion design challenge because of the multi-layered completion strategy that was required to effectively drain several of the pay units in each well. Multi-zone, frac-pack completions consisting of isolation packers and sand control screens with separate pumping and production sleeves were used to provide sand control. An inner-string of additional isolation seals, gauges and intelligent control valves were run to provide zone specific monitoring and production control.
The initial well completion work resulted in high skin values during production. Review of post-stimulation data helped in identifying the shortcomings in designs and completion procedure. As a result of this, changes were made in the completion procedures, and frac-pack designs were tailored to suit the purposes. When these changes were implemented in subsequent wells, an improvement in well performance was seen, mostly in the form of reduced skin.
The paper details this evolution, including favorable modification of completion procedures, as well as, the changes in pump schedule, treatment planning, and delivery methods during the frac-pack campaign. The benefit of adopting such an approach, using the methods and techniques used in this campaign, can be applied to similar fields under development.