Suo, Yu (University of New South Wales) | Chen, Zhixi (University of New South Wales) | Rahman, Sheik (University of New South Wales) | Xu, Wenjun (University of New South Wales and Southwest Petroleum University)
Hydraulic fracturing is a significant way to improve the productivity of the unconventional reservoir with low permeability and porosity. Current hydraulic fracturing simulation models are mostly based on poro-elastic theory. However, for rocks such as shale, the viscoelastic feature has been observed in both field investigations and laboratory experiments. This paper presents a 3D numerical model for fracture propagation in viscoelastic shale gas formations using ABAQUS platform. The cohesive elements based on damage mechanics were adopted to simulate the initiation and propagation of hydraulic fractures. The model was used to investigate formation properties and treatment parameters on fracture geometry, especially the fracture behaviour when entering into the barrier formations. It is found that higher treatment pressure is required to initiate and propagate the hydraulic fracture and the fracture is wider but shorter in poroviscoelastic formation comparing to poro-elastic formation. The higher differential in-situ stress, tensile strength and Young modulus in barrier formations and lower fracturing fluid injection rate and lower fracturing fluid viscosity have positive effect on the controlling of fracture vertical growth and restricting hydraulic fracture within the pay zone. Results of this study will provide the industry a better understanding of hydraulic fracture behaviour in shale gas formations.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited.
Song, Huifang (School of Petroleum Engineering, University of New South Wales) | Liang, Zhirong (School of Petroleum Engineering, University of New South Wales) | Chen, Zhixi (School of Petroleum Engineering, University of New South Wales) | Gholizadeh Doonechaly, Nima (School of Petroleum Engineering, University of New South Wales) | Arns, Ji-Youn (School of Petroleum Engineering, University of New South Wales) | S. Rahman, Sheik (School of Petroleum Engineering, University of New South Wales)
Unconventional gas reservoirs (shale gas, tight gas and coal bed methane) constitute a large percentage of natural gas supply. Hydraulic fracturing is commonly used to break-up rock matrix and connect natural fractures and cleats to create gas flow pathways. Application of hydraulic fracturing, however, poses several problems including extremely low matrix permeability and poor connectivity between matrix and fractures. Several studies have been made in field and in laboratory to open and interconnect these natural fractures and cleat system with cold fluid, results of which are found to be promising. In this paper we present a parametric design analysis as to the application of thermal stress (due to cold fluid injection) induced hydraulic fracture treatment.
Propagation of natural fractures and cleats surrounding the induced hydraulic fracture by thermal induced stress is investigated in hydro-thermo-mechanical (THM) framework both numerically and experimentally to quantify the effect of thermal shock. Increase in fracture (natural fractures and cleats) aperture and propagation is modelled by cohesive zone method. Numerical results were validated by injecting cold liquid in 1 in diameter coal sample and changes in permeability were recorded. During the same time, the changes in aperture and length of cleat and fractures respectively were monitored by µ-CT.
Numerical results show that as the cooling front due to invasion of cold fluid moves into the matrix, it facilitates initiation of cracks in planes of weakness and/ or causes the cleats and natural fractures to open and propagate some distance away from the hydraulic fracture surface. This phenomenon is more pronounced around crack tips due to severe thermal straining. It was also observed that SIF and J-integral of cracks are much higher than that without thermal effect.
Thermal stress induced cleats and natural fracture propagation surrounding the treatment area extends the reach of the hydraulic fracture which otherwise could not have been connected. In this paper we present a quantitative analysis of the effect of thermal stress on fracture/ cleat propagation behaviour so that an improved understanding is gained with regard to the application of low temperature fracturing.
This paper presents a comprehensive approach to the design of hydraulic-fracture treatments, accounting for anisotropic stress conditions, rock properties, and the effect of pore-pressure changes caused by production in tight gas reservoirs. This has allowed us, among other opportunities, to design a refracture treatment. The poroelastic model is also coupled with a production-optimization scheme to optimize the design parameters for hydraulic-fracture treatments. A case study of refracture treatment has been carried out for a typical tight gas reservoir. This study has shown that the fracture treatment can be optimized successfully to increase the net present value and/or ultimate gas recovery. This study also has demonstrated that a second fracture treatment can be performed after a period of production from the same treated interval to maintain production without the drilling of additional wells.
Traditionally, designing a fracture treatment entails a 3-step procedure: (1) determination of the fracture geometry on the basis of a given set of treatment parameters, (2) estimation of production from the designed fracture geometry, and (3) estimation of net present value for the designed treatment. A set of treatment parameters that gives the highest net present value is considered to be the optimum treatment design. This procedure, however, does not account for events that occur over the production life of the treated well: low reservoir pressure, proppant degradation, or embedment that results in severe fracture-conductivity impairment. Our approach seeks to provide a remedy for these problems by optimizing the fracture treatment and maximizing net present value for a given reservoir condition.
The approach makes use of production-induced reservoir stress changes. This phenomenon has been observed both in the field (Wright and Conant 1995) and in the laboratory (Bruno and Nakagawa 1991). Previous studies suggest that with pore-pressure depletion, the effective stress orthogonal to the fracture changes faster than one along the fracture, causing stress reversal. This stress reversal could be exploited to improve reservoir productivity by means of a refracture treatment (secondary fracture treatment). The secondary fracture created at this stage propagates in a direction different from that of the initial fracture. This refracture treatment has the potential to increase production by intersecting undrained areas.
In recent years, application of oriented refracturing has been gaining attention. Production tests and history matching, as well as downhole and surface tiltmeter measurements, show that a secondary fracture, under certain conditions, can reorient up to 90° relative to an initial hydraulic fracture. A schematic of fracture reorientation is presented in Fig. 1.
Production from the initial fracture causes a local depletion of pore pressure around the wellbore and the fracture. Because of poroelastic effects, the pore-pressure depletion changes stresses in the reservoir (Biot 1941, 1956; Geertsma 1957; Raghavan and Miller 1975; Rice and Cleray 1976; Verruijt 1969). The horizontal stress component parallel to the initial fracture (maximum horizontal stress) is reduced more rapidly than the perpendicular component (minimum horizontal stress). If the induced change in stress overcomes the initial stress differential, then the direction of the minimum horizontal stress becomes the direction of the maximum horizontal stress (stress reversal) around the wellbore. Studies have shown that stress reversal is more pronounced in regions with high anisotropic horizontal permeability (Siebrits et al. 1998). Under these conditions, a secondary fracture can be initiated and propagated along a different azimuth plane (up to 90° from the initial fracture) (Elbel and Mack 1993; Siebrits et al. 1998). The fracture may continue to propagate along the new azimuth for some distance beyond the isotropic boundary (see Fig. 1), depending on formation toughness. Note that the stress changes reach their maximum value and then diminish with further pore-pressure depletion (Siebrits et al. 1998). Thus, an optimal time window can be obtained to carry out a potential secondary fracture treatment.
A holistic approach that takes advantage of stress changes induced by production operations in the design of secondary fracture treatments is used. Four models were used for this purpose: (1) poroelastic reservoir model, (2) fracture-geometry model, (3) production model, and (4) economic model. In the following section, we describe the poroelastic model and conduct a sensitivity analysis to show how different parameters affect refracture treatments. Following this, an optimization technique to design an optimum refracture treatment for a tight gas reservoir is presented. The optimization technique combines the fracture-geometry model, the production model, and the economic model.
This paper presents a comprehensive approach to the design of hydraulic fracture treatments which takes into account anisotropic stress conditions, rock properties and the effect of pore pressure changes due to production in tight gas reservoirs. This has allowed us, among others, to design a re-fracture treatment. Our poroelastic model is also coupled with a production optimization scheme to optimize the design parameters for hydraulic fracture treatments.
In this paper, we present the results of a study carried out in a tight gas reservoir. Our study has shown that the fracture treatment can be successfully optimized to increase the NPV and/or ultimate gas recovery. We also demonstrated through this study that a second fracture treatment can be carried out after a period of production from the same treated interval to maintain production without drilling additional wells.
Coupled poroelastic response of formation around wellbore is expected to differ from the classic linear elastic theory when subject to changes in the state of stress. This may lead to redistribution of stress and pore pressure around the wellbore and consequent time-dependant wellbore deformation. These effects could cause delayed wellbore failure, loss of circulation and even the total loss of the well, especially in the case of underbalanced drilling. This paper presents a fully coupled poroelastic model developed for wellbore stability analysis with particular emphasis on fluid flow induced stress changes around wellbore. By using finite element methods, the model is able to simultaneously compute the geomechanical and hydraulic variables.
In analogy with the common approach of wellbore stability analysis through initial and infinite time stresses calculation, the model can evaluate transient stress and pressure profiles to demonstrate the behavior of a wellbore throughout its history. This allows us to widen the safety mud weight window which leads to reduced drilling time and costs. The time of failure can be predicted by using modified Mohr-Coulomb criteria for breakout failure and tensile failure criteria for fracture. Thus, the coupled poroelastic approach can examine the factors influencing the wellbore stability more accurately than linear elastic method.
The model was used to analyse wellbore stability in different formation types, stress conditions and drilling situations. Time-dependent shear stress distributions are presented so that they can be compared with shear strength of these rocks at different depths to select appropriate mud weights for underbalanced drilling.
This paper presents the results of a laboratory study on the effect of different fracture fluid systems on permeability impairment of a typical coalbed methane (CBM) reservoir. These fluid systems include conventional gel fluids (linear and cross-linked gel), gel fluid with surfactant and a viscoelastic fluid system. A series of flow tests on coal plugs were conducted under simulated reservoir conditions to assess permeability reduction due to matrix swelling and cleat plugging by gel fluids. Tests included surface behavior of different fracture fluids and surfactants on coal surface, degrees of matrix swelling and plugging of fractures and cleat systems by fracture fluids.
The results of these tests have shown that permeability impairment induced by matrix swelling is highly irreversible. This irreversible damage can be prevented to a certain extent by conventional practices of adding certain types of salt (such as KCl) into fracture fluids. Both linear gel and cross-linked gel fluids cause a significant reduction (around 70%) in permeability of CBM reservoirs. Addition of KCl along with certain types of surfactants to gel fluid can marginally improve gel clean up. However, the permeability impairment could be as high as 60%. With the use of viscoelastic fluid system, on the other hand, permeability impairment can be as little as 20 to 30%. This means the viscoelastic fluid system has a great potential in reducing permeability impairment which in turn can help rapid dewatering from CBM reservoirs and increase production.
As exploitation of unconventional resources such as coalbed methane (CBM) reservoirs becomes increasingly essential, there is a growing need to develop hydraulic fracture treatment design for these reservoirs with complex geology and stress conditions. Conventional methodologies have failed to address the difficulties involved in the design and execution of fracture treatments in these complex conditions. These include unrestricted height growth breaking through the roof and floor of the coal seam, massive fluid loss as a consequence of the high leak-off formation and poroelastic effects. This paper presents an integrated approach to optimise hydraulic fracture treatments and addresses the associated problems encountered during the hydraulic fracturing process.
A 3D poroelastic, finite element based numerical design tool has been developed to describe the fracture geometry for given reservoir and operating conditions. This is coupled with a production model appropriately quantifying the post-frac productivity of a CBM reservoir. Finally, cost analysis is carried out to optimise design parameters against different production scenarios using a hybrid genetic-evolutionary optimisation tool.
Our study has shown a significant improvement in understanding the fracture containment mechanisms and impact of poroelastic effects in stimulating CBM reservoirs.Furthermore, results of this study demonstrate that use of an integrated approach in the design of hydraulic fracture treatments results in a higher yield and cost-effective exploitation of CBM prospects.
Exploitation of unconventional resources such as coal bed methane reservoirs is motivated by the growing demand for hydrocarbon supply. This calls for a cost-effective stimulation methodology to maximise profit derived from these resources.Due to their characteristic difference with the conventional oil and gas reservoirs, largely accepted norms in the hydraulic fracturing literature are in many ways inadequate to address problems associated with hydraulic fracture stimulation in CBM reservoirs. In particular, the complexity in stimulating CBM reservoirs stems from the highly heterogeneous nature of their in-situ stress distribution and their naturally fractured and high leak-off characteristics. Furthermore, their production mechanism is significantly different from conventional gas wells since dewatering is required to lower the reservoir pressure and allow gas to desorb. When fracturing CBM reservoirs, abnormally high treating pressures often occur. In addition, stress barriers restricting fracture height growth may be inexistent.
Conventional methodologies have failed to address the difficulties involved in the design and execution of fracture treatments of reservoirs with complex geology and stress conditions such as coal bed methane (CBM) reservoirs. This paper presents an innovative technique to optimize and design hydraulic fracture treatments in naturally fractured CBM reservoirs. This methodology integrates (1) a three dimensional (3D), finite element based numerical design tool to predict the fracture geometry for given reservoir and operating conditions, (2) a production model to estimate fluid flow in the CBM reservoir, and (3) cost analysis to optimize the design parameters against different field scenarios using a hybrid genetic-evolutionary optimization tool.
The technique has been used to design fracture treatments in a coal bed methane reservoir to illustrate its potential benefits in improving the reservoir's productivity. Results of this study have shown that the use of a 3D geometry model enabled realistic post-frac productivity analysis. This provided reliable conservative estimates on the revenue derived from the stimulation program. Furthermore, the optimization approach allowed operators to incorporate operating constraints based on sound industry practice and company guidelines for a cost-effective exploitation of CBM reservoirs.
As exploitation of unconventional resources such as coal bed methane (CBM) reservoirs becomes increasingly important, the need to design hydraulic fracture treatments for these complex reservoir conditions arises. Ideally, hydraulic fracture treatment design is aimed at creating long, well-contained fractures for maximum productivity. Fracture migration to the bounding layers is akin to failure of the stimulation job. Problems posed by unconfined fracture growth may include massive fluid loss and screen out in conventional petroleum reservoirs. In CBM reservoirs, this event poses a more serious problem. When the roof and floor of the coal seam are fractured, this break may provide a conduit that will allow the continuous recharge of fluid into the pay zone from adjacent, more permeable layers and thus, maintain the pressure of the reservoir. When this happens, the pressure will not drop to the required critical pressure for methane desorption. This is frequently observed in CBM reservoirs where the minimum in-situ stress in the coal seam may be higher or equal in magnitude to the stresses of the bounding rocks1, 2. In some cases, fracture height growth was confirmed to reach at least 500 ft, encompassing several thin layers of coal seams3,4. Containment of long fractures for increased reservoir productivity becomes a major difficulty.
Previous works in the design and planning of fracture treatments for CBM reservoirs have not been very effective due to lack of a tool for realistically predicting the fracture geometry. Most of the current works in fracture modeling has relied on the simplified two dimensional (2D) and pseudo three dimensional (pseudo 3D) models which only give an approximate description of the real fracture geometry. In the 2D models it is simply assumed that fracture height is equal to the pay thickness. This assumption is valid only for conventional petroleum reservoirs where there is adequate stress contrast to contain the fracture within the pay zone. In the case of coal bed methane reservoirs where there might not be adequate stress contrast, this assumption does not hold true. Pseudo 3D models may be employed to account for height variation due to differences in the minimum horizontal stress of each layer. However, since pseudo 3D models assume constant material properties, the effect brought about by the large difference between the elastic modulus of the coal seam and the bounding layers are unaccounted for. Thus, use of 3D fracture modeling is required to reliably approximate the fracture geometry.
Modeling of fracture network is an essential step for developing naturally fractured reservoirs study. It helps to develop a best scenario for hydraulic fracture treatment, to design an optimum production method and to evaluate reservoir potential. This paper presents an integrated methodology for modeling fracture network by utilizing object modeling and global optimization. It also describes a field study to evaluate the methodology's effectiveness. Firstly, as an object-based model, each fracture is presented and treated as a discrete object, characterized by its centre location, orientation and size. Object-based modeling allows the output of spatial distribution and details of discrete fracture network. From observed data sources such as seismics, outcrops, well logs and images, etc., we characterize fracture and field attributes, including fracture density, fracture parameters' statistics. Then, we perform a statistical analysis on fracture properties to identify density functions and distribution patterns. The essential feature of this approach is the formulation of the objective function. Various variogram measurements, modified multi histograms and other statistical properties are selected, so that the objective function is able to adequately describe the representative field data. In the next step, we use global optimization (simulated annealing algorithm) to produce result fracture network, by optimizing the objective function. This network matches the field characterized fracture attributes and characteristics. A global optimization method such as simulated annealing is able to honor more data than conventional geo-statistical simulation techniques. Case study shows that the modeling methodology mapped discrete fracture network very closely to the observed fracture distribution and properties.