Many shale gas and ultra-low permeability tight gas reservoirs can have matrix permeability values in the range of tens to hundreds of nanodarcies. The ultra-fine pore structure of these rocks can cause violation of the basic assumptions behind usage of Darcy's law. Depending on a combination of P-T conditions, pore structure and gas properties, non-Darcy flow mechanisms such as Knudsen diffusion and/or gas slippage effects could be important. Quantifying these effects is critical for correcting laboratory permeability measurements to obtain true (intrinsic) matrix permeability; several authors have also noted that corrections for these effects may also be important when analyzing field data. In order to make corrections for non-Darcy flow, numerous authors have quantified these effects as an apparent permeability that changes as a function of Knudsen number or gas pressure. There are now many correlations available for quantifying apparent permeability changes, but it is not known how much impact they really have on the long term production performance of shale gas wells.
In this work, we summarize the various methods for quantifying non-Darcy flow in unconventional gas reservoirs, and compare the apparent permeability and slippage factor predictions for all the models we have compiled. For determining the impact of the model predictions on well performance, we incorporate the apparent permeability predictions of each model into a numerical simulator, and compare rate-time and cumulative gas-time forecasts for each scenario. The importance of dual porosity (which is usually assumed necessary for shale gas) is also examined. The results of this work are important in several aspects. First, the differences between various formulations of the apparent matrix permeability in shales are illustrated. Secondly, the impact of non-Darcy effects on history matching and recovery forecasting is demonstrated. Finally, it is shown that there may not be a need for dual porosity modeling in certain cases.
The results of this study will be important to professionals involved in laboratory measurement of matrix permeability in unconventional gas reservoirs, modeling well performance, and forecasting shale gas recovery.
The advances in hydraulic fracturing technology and horizontal well completions have led in recent years to rapid rise in exploitation and development of tight gas and shale plays all over the world, and particularly in North America. The popularity of new field technology has in fact raised many new questions. In particular, for forecasting the productivity and EUR of multifractured horizontal wells, it is not clear if conventional reservoir simulation concepts can be adapted for modeling or if extra physics must be included to obtain realistic solutions.
This paper presents various methods to model multifractured horizontal wells in tight gas sands using a conventional reservoir simulator coupled with geomechanics. Two actual wells in the same formation but with different fracturing techniques (i.e., X-link gelled water fracs and un-gelled water (slick water) fracs) are studied. Detailed investigation of the role of fracture conductivity, effects of initial permeability level and net pay thickness, assumed size of the stimulated reservoir volume (SRV), and pressure or stress dependent permeability of the SRV and virgin reservoir were carried out by history matching the rate and cumulative production. It was established that i) history match is not possible without use of stress or pressure dependent permeability and ii) permeability dependence of pressure inside stimulated reservoir volume must be larger than in the rest of the reservoir. It was also observed that the standard method for using the same geomechanical data both in uncoupled reservoir and coupled geomechanical model will give incorrect results in terms of cumulative production.
A new method based on uniaxial deformation theory is proposed to more accurately approximate the geomechanical effects in conventional reservoir simulators without running a fully coupled geomechanical simulator. The results from uncoupled reservoir modeling using the new method for correcting the permeability data for poroelastic effects were remarkably similar to rigorously coupled geomechanical modeling.
This work will be of importance to engineers in analyzing and forecasting production performance of multifractured horizontal completions using numerical models. It will allow engineers to use uncoupled (conventional) reservoir modeling as a practical approximation of more complex coupled geomechanical models.
The key property controlling reservoir productivity is permeability. Permeability enhancement during hydraulic fracturing, to some degree, can be inferred from microseismic monitoring. In this study, we numerically model microseismicity occurring along the hydraulic fracture, compare it to the recorded microseismic activity and predict permeability of the reservoir based on the motion on the fractures.
We present a fully coupled fluid-geomechanical model of hydraulic fracture propagation in the heterogeneous reservoir. The fluid part is solved using the commercial code Geosim and the geomechanical and microseismic solutions are constructed using the damage mechanics. Permeability enhancement is calculated from the fracture displacement. We distinguish three fracture scales in terms of model implementation: the main hydraulic fracture (~100 m scale), new fracturing on the scale of microseismic events (~ 2-10 m scale) and microfractures (under 2-10 m scale).
We apply this technique to the hydrofracturing treatment in the Bossier sandstone where we focus on the effect of the pre-existing fracture heterogeneities on the reservoir microseismic activity. We use the observed microseismicity as a guide to describe the reservoir heterogeneity. Even though we match the observed microseismicity very well in time and space, the permeability enhancement related to the formation of the new fractures is very scattered and the increased leak-off does not change in time enough to characterize the total leak-off into the formation. Permeability determined from the new fractures is several orders lower than permeability of the main hydrofracture. Such an enhancement is not efficient in this case and cannot drive enough fluid into the formation and therefore permeability of the main fracture remains the main driving mechanism. However, the effect on the production may be different and needs to be explored. The heterogeneity of the reservoir seems to be a very important property for the success of the hydraulic fracturing.
The key property controlling reservoir productivity is permeability. Permeability enhancement during hydraulic fracturing, to some degree, can be inferred from microseismic monitoring. In this study, we numerically model microseismicity occurring along the hydraulic fracture, compare it to the recorded microseismic activity and predict permeability of the reservoir based on the motion on the fractures. During the hydraulic fracturing, reservoir permeability changes due to the formation of fractures on various scales (primary single plane tensile fracture and shear fractures) and due to the opening and closing of the pre-existing joints and fractures in the reservoir. This paper focuses on testing mainly the effect of fractures on the scale of microseismic events (2-10 m scale). However, the occurrence of the microseismic events is necessarily linked to the fracture scales above and below the microseismic scale. In this paper, we distinguish three fracture scales in terms of model implementation: the main hydraulic fracture (~100 m scale), new fracturing on the scale of microseismic events (~ 2-10 m scale) and microfractures (under 2-10 m scale).
The thermal recovery of bitumen reservoirs by steam assisted gravity drainage (SAGD) is often designed to maximize the operating pressure while maintaining a safe and economic operation. In general, higher operating pressure can reduce thermal efficiency due to heat losses to over/underburden formation, but the other benefits usually compensate. To name a few, higher steam temperatures can maximize the reduction of oil viscosity, enhance permeability associated with lower effective stress and shear dilation, and give a larger pressure window to allow flexible control of the producer. This is especially important for shallow reservoirs where the pressure window for injection and production is smaller. The limitation of the maximum operating pressure is then based on maintaining caprock integrity. Thus, shear and tensile failure mechanisms should be quantified and managed.
This paper presents a methodology to perform a geomechanical analysis of caprock integrity for SAGD operation and illustrates the available approaches. Both analytical and numerical approaches are compared demonstrating their usefulness. Main factors in the analysis are the knowledge of the initial stress state and proper representation of the complexity of the geomaterials. A typical initial stress state for a northern Alberta SAGD property, Suncor's MacKay River project, is presented showing the potential for low initial minimum total stress and elevated initial shear stress levels. The stress-strain behavior for the MacKay River sand and caprock materials is discussed focusing on the potential for shear dilation in the sand and shear strength behavior in the caprock. An elasto-plastic constitutive model is used to represent the sand and caprock materials. The increase in pressure and temperature alter the stress state and disturb the soil matrix. This disturbance results in shear dilation of the sand matrix creating regions of enhanced permeability and porosity. Also, the transfer of stress and strain to the caprock causes dynamic stress changes and, therefore, dynamic behavior of shear and tensile failure conditions. Calculations are presented showing the stress paths associated with SAGD operations, suggesting better design of lab testing programs and the implications for shear dilation in the sand and shear failure in the caprock. Finally, the results are used to demonstrate locations that are most likely at risk for potential tensile and shear failure. Stress ratios are used to summarize the analysis and quantify and monitor the failure mechanisms.
The above methodology has been developed and applied in several studies of other SAGD projects and aided the operators in the optimization and permitting the operating conditions.
It has been observed that the shale gas production modeled with conventional simulators/models is much lower than actually observed field data. Generally reservoir and/or stimulated reservoir volume (SRV) parameters are modified (without much physical support) to match production data. One of the important parameters controlling flow is the effective permeability of the intact shale. In this project we aim to model flow in shale nano pores by capturing the physics behind the actual process. For the flow dynamics, in addition to Darcy flow, the effects of slippage at the boundary of pores and Knudsen diffusion have been included. For the gas source, the compressed gas stored in pore spaces, gas adsorbed at pore walls and gas diffusing from the kerogen have been considered. To imitate the actual scenario, real gas has been considered to model the flow. Partial differential equations were derived capturing the physics and finite difference method was used to solve the coupled differential equations numerically. The contribution of Knudsen diffusion and gas slippage, gas desorption and gas diffusion from kerogen to total production was studied in detail. It was seen that including the additional physics causes significant differences in pressure gradients and increases cumulative production. We conclude that the above effects should be considered while modeling and making production forecasts for shale gas reservoirs.
Nitrogen (N2) stimulation has become the preferred technique for stimulation of coal seams in the Horseshoe Canyon play in Alberta. It consists of stimulating each seam by pumping at very high rates for short time (2-4 minutes). Because the coal is producible at shallow depths, the Energy Resource Conservation Board (ERCB) has been developing and updating regulatory guidelines that aim to protect the freshwater supply.
This study was undertaken to improve the understanding of the process and provide recommendations on the regulatory guidelines for shallow depth (less than 200 m). The study was provided with extensive data from the industry (more than 20,000 fractures in more than 2,000 wells) and has carried out several types of analyses to estimate fracture orientation and dimensions and their dependence on N2-injection rate and duration and on reservoir parameters. This included statistical analysis of large amounts of surface pressure data, pressure-transient analysis (PTA) of downhole pressure data, analysis of fracture-mapping data, and conceptual simulations of the injection process using coupled reservoir and geomechanical models. Coupled geomechanical modeling provided a realistic physical model of the process (in comparison with conventional models). Stress dependence of coal permeability and permeability anisotropy were shown to be the controlling mechanisms. This model was then used to investigate height-growth mechanisms.
After considering the results of the analysis, its limitations, uncertainties in geological description of the coal and shale sequences, available case histories, and other factors, recommendations were made for modifications, resulting in the revised ERCB Directive 27, Shallow Fracturing Operations--Restricted Operations, released 14 August 2009.
Hydraulic fracturing is a stimulation technique essential for economical development of tight gas and shale gas reservoirs. Analysis of the performance of fracturing jobs and optimization of the treatment design requires modeling which accounts for all important features of the process and ideally covers both the treatment and post-stimulation production of the well. It is now well established that the productivity of the wells is due not only to the classical tensile single plane fracture (SPF), but to the development of an enhanced permeability region (stimulated reservoir volume or SRV) around it due to shear fracturing and/or stimulation of existing dual porosity. The shape and size of the SRV depends not only on the injection process but also on the geomechanics of the reservoir. Current techniques are not able to predict its dependence on frac job parameters, which precludes any meaningful optimization. Typically the SRV size is assumed (e.g., from microseismic) in production forecasting.
In this work we have developed a new coupled geomechanical and flow model for analysis and optimization of tight and shale gas treatments. The formulation includes the propagation of a tensile (SPF) fracture and dynamic development of the shear failure. Non-fractured blocks are assumed to be of linear elastic material; whereas in the failed blocks, fractures and rock compliance matrices are homogenized to form an equivalent compliance matrix. Simple Mohr-Coulomb and tensile failure relationships were used as the criteria for detecting fracture creation. Hyperbolic functions are used to describe the fracture normal and pre-peak shear deformations while the post-peak shear behavior follows an elasto-plastic model. The permeability enhancement during the fracturing process is computed and is the principal coupling between the flow and geomechanics. The model is 3-dimensional and treats both normal and shear behaviour of fractures. The simulation results reveal that shear fracturing will be the dominant fracturing mechanism in cases where the rock cohesion is low and the deviatoric stress is high, whereas tensile fracturing prevails in other conditions.
The new model will be a realistic tool for analyzing the dependence of the well productivity on design parameters such as stage volume and pumping rate, spacing between stages, etc. It can be also used to screen shale plays for the most favorable geomechanical conditions.