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Abstract Uniformity of proppant distribution among multiple perforation clusters affects treatment efficiency in multistage fractured wells stimulated using the plug-and-perf technique. Multiple physical phenomena taking place in the well and perforation tunnels can cause uneven proppant distribution among multiple clusters. The problem has been studied in the recent years with experimental and computational fluid dynamics (CFD) methods, which provide useful insights but are impractical for routine designs. Simplified models that incorporated the proppant transport efficiency (PTE) correlation derived from the CFD results in a hydraulic fracture model have been also presented in literature. In this paper, we present a numerical model that simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling including bed formation, rate- and concentration-dependent pressure drop, PTE, and dynamic pressure coupling with the hydraulic fractures. The model is efficient and is designed to be an independent wellbore transport model so it can be integrated with any fracture models, including fully 3D and/or complex fracture network models, for practical design optimization. The model predictions are compared and found to agree with previously published studies. Parametric studies demonstrate sensitivity of proppant distribution to grain size, fluid viscosity, and pumping rate for fixed perforation designs. Analysis of the simulation results shows that the dominant cause of uneven proppant distribution is proppant inertia. Possible slurry stratification is less important, except for the cases with relatively low flow rates and near toe clusters. Accordingly, proppant distribution is less sensitive to perforation phasing than to the number of perforations in clusters. Alterations of the number of perforations per cluster within a stage enable achieving more even proppant distribution.
Xu, Wenyue (Schlumberger-Doll Research Center) | Prioul, Romain (Schlumberger-Doll Research Center) | Berard, Thomas (Schlumberger-Doll Research Center) | Weng, Xiaowei (Schlumberger) | Kresse, Olga (Schlumberger)
Abstract This work introduces a new set of energy-balance-based criteria for the vertical growth of a plain-strain planar hydraulic fracture across a horizontally laminated reservoir formation with heterogenous layer properties and multiple weak interfaces. Combined with Coulomb's friction law for mechanical balance along sliding interfaces, these criteria were built into a novel semi-analytical model of fractional fracture height growth. The model was then applied to investigate the growth of hydraulic fractures in an idealized symmetric three-layer rock formation, with the upper and lower layers acting as barriers to the growth. Preliminary modeling results show how the vertical growth of a hydraulic fracture is influenced by the various mechanical/energy barriers. Three primary types of barrier behaviors are identified. A stress barrier leads to gradually increasing fluid pressure when the barrier layer is crossed. A toughness/modulus barrier, on the other hand, results in an immediate sharp increase in fluid pressure followed by gradual decline in pressure. The effect of individual sliding interfaces is similar to that of a toughness/modulus barrier. The cumulative effect becomes more important when multiple closely spaced interfaces are present. A formation layer containing multiple closely spaced weak interfaces behaves collectively much like a stress barrier.
Abstract Commercial hydraulic fracture software are generally based on the planar 3D model (PL3D) or the Pseudo 3D model (P3D). The PL3D model is more accurate but very CPU intensive, which makes it unsuitable to simulate complex hydraulic fracture networks due to the interaction with natural fractures. The pseudo-3D model is faster but considers separately the vertical and horizontal propagation of the fractures. In recent years, a sophisticated P3D-based complex hydraulic fracture network model, the Unconventional Fracture model (UFM) was developed that can simulate complex physical mechanisms such as interaction with natural fractures, stress shadow and the proppant placement in the complex fracture network. However, one of the main challenges still faced by such simulators is to accurately predict the height growth in formations with heterogeneous mechanical and stress properties. One assumption of the P3D model is the fracture is being initiated and extended in a lower stress layer than the adjacent layers. In practice, the assumption is not always satisfied, leading to inaccurate or unstable height growth. A comparison of these two models through examples illustrates the situations where P3D model works well and where it does not, and the difficult compromise between accuracy and computational efficiency. A better compromise can be achieved through a new Stacked Height Growth model (SHG). This model is an enhancement to the P3D model, consisting of multiple rows of elements vertically stacked, to more precisely account for the effect of vertical stress heterogeneity, and to allow multiple horizontal propagation fronts. The width profile and stress intensity factors at the top and bottom depend on the stress and pressure profiles along the stack of elements. The theoretical background of the model is presented. Comparison shows good agreement with the PL3D model for cases that the P3D model cannot accurately simulate, and at a fraction of the computational cost of PL3D. A particularly interesting feature of the SHG model is its flexibility to transition smoothly from a 1D cell-based model such as the P3D model, to a fine scale 2D gridding in the fracture plane. This feature greatly facilitates the implementation of other modeling features into the fracturing simulator. For example, the SHG model can be used to simulate interaction of hydraulic fractures with Multi-layer Discrete Fracture Networks (MDFN), to better model naturally fractured reservoirs. The SHG model can also be used to model offsets of hydraulic fractures through weak interfaces called ledges. The model can capture the influence of these discontinuities on the proppant placement. Another example, is how a fine 2D gridding using the SHG model can predict proppant placement as accurately as a PL3D model. These extensions of the SHG model have been implemented into the UFM model and are illustrated in this paper through several examples.
The interaction of hydraulic fractures with the pre-existing natural fractures may play a major role in increasing productivity from unconventional formations. When a hydraulic fracture meets a natural fracture, the hydraulic fracture can cross the natural fracture or be arrested. If the natural fracture is permeable, fracturing fluid can leak from the hydraulic fracture into the natural fracture causing elevation of pore pressure in the natural fracture and reducing the effective normal stress acting on the natural fracture, which could then lead to shear failure or slippage along the natural fracture plane. Shear-slip causes dilation, potentially increasing fracture conductivity and enhancing fluid flow deeper into the natural fracture. The conductivity of unpropped shear-induced fractures can play an important role in enhancing the productivity from ultralow-permeability formations like shale. In this paper, we first evaluate analytically the shear-slip condition and its propagation along a natural fracture under remote normal and shear stresses, when it is exposed to the fluid pressure in a hydraulic fracture. Analytical approximations under some limiting conditions are considered. A rigorous 2D numerical model based on coupling between fluid flow and rock deformation using displacement discontinuity method and fluid flow in the fracture is then described. The results of numerical simulations are presented to illustrate the effect of rock stress anisotropy, initial natural fracture conductivity, and fluid properties on the evolution of the fluid and slip fronts along the natural fracture and the associated permeability enhancement.
In the last decade, following the success of horizontal drilling and multistage fracturing in the Barnett Shale, exploration and drilling activities in shale gas and shale oil reservoirs have skyrocketed in the US and abroad. Economic production from these reservoirs depends greatly on the effectiveness of hydraulic fracturing stimulation treatment. Microseismic measurements and other evidence suggest that creation of complex fracture networks during fracturing treatments may be a common occurrence in many unconventional reservoirs [1-3]. The created complexity is strongly influenced by the preexisting natural fractures and in-situ stresses in the formation. To optimize the fracture and completion design to maximize the production from these reservoirs, engineers must have a good understanding of the fracturing process and be able to simulate it to obtain information such as the induced overall fracture length and height, propped versus unpropped fracture surface areas, proppant distribution and its conductivity, and potential enhanced permeability through stimulation of the natural fractures.
The majority of planar hydraulic fracture models use two distinct approaches. The first one, referred to as the planar 3D model, is more accurate but also very CPU intensive. The second one is referred to pseudo-3D (P3D) model, and separately considers the vertical growth and horizontal propagation of the fractures. This approach is less CPU intensive, but requires the fracture being initiated in the lower stress layer. In practice, this assumption is not always verified, and the fracture height growth can become unstable. This paper presents a new model as an enhancement of the P3D, which consists of multiple rows of elements vertically stacked and connected. For each row of elements, the assumption of the fracture front being in the lower stress layer is satisfied locally. The width profile and stress intensity factor at the top and bottom of the fracture depend on the stress profile and the pressure profile along the stack of elements. This model predicts the fracture height more accurately than the P3D model, and gives results close to the ones from the full planar 3D model.
The rapid development of shale resources in the past decade has brought a focus on the process of hydraulic fracturing. Shale reservoirs tend to be characterized by a complex 3D stress field and vertically heterogeneous mechanical properties, which have always been challenging for hydraulic fracturing modeling and particularly for properly predicting the shape of an induced fracture . Most state-of-the-art planar fracture simulators use two distinct approaches. In the first one, referred to as the planar 3D model (PL3D), the fracture is assumed to be a plane and its entire footprint is discretized into elements. The equations governing fluid flow, elasticity, and mass balance are solved numerically, coupled with the fracture propagation rules. This approach is very accurate but also very CPU intensive . This type of model is mostly used when a large portion of the fracture propagates outside of the zone where the fracture was initiated and significant amount of vertical flow is expected. The second approach is based on the cell-based pseudo-3D (P3D) model , which separately considers the vertical growth and horizontal propagation of the fractures. In this approach, the width profile and fracture height are calculated based solely on the local pressure and local vertical stress profile. This approach is less CPU intensive, but relies on several assumptions including the fracture being initiated and its leading front propagating in the lower stress layer compared to the neighboring layers above and below. If this is not the case, the fracture height growth can become unstable, since it is not directly correlated to the global fracture mass balance as in the PL3D model, and this can lead to significant inaccuracy in the predicted fracture height growth.
Abstract Advances in horizontal drilling and new practices in hydraulic fracturing have changed the paradigm of shale reservoirs in the last decade. Nevertheless, completion and stimulation engineers still face serious challenges due to the complex physics involved during hydraulic fracture propagation including hydraulic fracture interaction with natural fractures, stress shadow effects, and proppant transport in complex fracture networks. One of the main questions is how to optimize the number of stages and the placement of perforation clusters accounting for these complex physical phenomena and the wells' economics. To answer this question, it is necessary to analyze how the completion design and the fracturing process are related to the short and long term production. This paper investigates the relation between the production and the completion design. A state-of the-art, fracturing-to-production simulation workflow is used to carry out a parametric study on completion design. The fracturing simulations are performed with the unconventional fracture model (UFM) that models the hydraulic fracturing process in a complex formations with pre-existing natural fractures including interaction with natural fractures and between hydraulic fracture branches (stress shadow effects). The resulting complex fracture networks are then explicitly gridded to build an unstructured grid that is then passed to a numerical reservoir simulator to run the production simulations and accurately model multiphase reservoir flow around complex hydraulic fracture networks. The base case of this study represents a synthetic reservoir model replicating properties of the Marcellus shale. One of the main parameters investigated is the number of perforation clusters per stage for both a constant pumping rate and for a constant average rate per perforation cluster. We also investigated the influence of the number of stages on production, for a given lateral length and a given total treatment volume. The results from this study provide new understanding of the impact of completion design on production and illustrate its use to find optimum completion design based on modeling. For example, some results show that for a constant average rate per cluster a clear optimum can be found as function of the number of cluster per stage, while this task can be more challenging with a constant total pumping rate. Introduction Economic production from shale gas reservoir depends greatly on well spacing and proper completion design of the wells. Among the most important considerations for completion design are defining the number of stages, the number of perforation clusters per stages as well as the spacing between perforation clusters as well as deciding the type of treatment fluid, proppant and the quantities to use. This design has a significant impact on the economics of the well due to the usually large number of stages required to complete a shale gas or a shale oil well. It is not uncommon to have ten to twenty stages for a single well, with three to eight perforation clusters per stage. Each stage may involve two to three hours of pumping of more than 200,000 gallons of fluids and 250,000 lbs of proppants, in addition to time spent to perform the perforation work and the placement of packers to isolate between stages. Therefore, the time for completion and stimulation of a well in a shale reservoir can easily extend beyond a week with intense and large scale operations and logistics. This adds significantly to the capital expenditure of the well, and impacts its economic viability. In addition, the completion design can significantly impact the production outcome from the well, by defining where the well connects to the heterogeneous reservoir and influencing both the hydraulic fracture propagation and the proppant placement. In this context, the optimization of the completion design is a serious challenge but critical for the development of shale resources.
Abstract Production from shale reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. Cumulative experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. Nevertheless, shale reservoirs still bring challenges to stimulation engineers, due to the complex physics involving interactions with natural fractures, stress shadow effects and proppant transport in complex fracture network. One of the challenges regards fluid and proppant selection, in particular, the issue is how to achieve the desired fracturing fluid viscosity inside the fracture for optimum proppant placement into an expanding complex fracture network. The rheological properties of the fracturing fluid depend on its temperature history, hence understanding the temperature distribution in the hydraulic fracture network is a key consideration for a successful treatment and a more accurate fracture prediction. This paper investigates the relation between reservoir temperature, fracturing fluid properties and production through fracturing-to-production simulation workflow. The paper first presents a temperature model implemented into the UFM model, which is a comprehensive complex fracturing simulator for shale reservoirs, accounting for interaction with natural fractures, stress shadow effects, and proppant transport in a complex networks. Based on the fracture geometry, proppant placement, and reservoir properties, a semi-analytical production model UPM is used to estimate the production. This workflow is used to first understand the temperature distribution in the expanding fracture network and understand its evolution as a function of several parameters such as reservoir temperature and rheological properties of the fracturing fluid. Then the associated production forecast provides guidelines on how to achieve optimum proppant and fluid selection based on the reservoir temperature for maximizing production.
The recently developed Unconventional Fracture Model (UFM*) simulates complex hydraulic fracture network propagation in a formation with preexisting closed natural fractures, and explicitly models hydraulic injection into a fracture network with multiple propagating branches . The model predicts whether a hydraulic fracture front crosses or is arrested by a natural fracture it encounters, which defines the complexity of the generated complex hydraulic fracture network. While taking into account the leakoff of the fracturing fluid into the formation, the leakoff into the natural fractures should also be considered, especially in low-matrix permeability conditions. The transmissibility of natural fractures can become significant, and the fracturing fluid can penetrate into natural fractures. Different regions can coexist along the invaded natural fracture: hydraulically opened region filled with fracturing fluid, region of still closed natural fracture invaded by fracturing fluid due to natural fracture permeability, and the region of natural fracture filled with original reservoir fluid. Explicit modelling of hydraulic fractures interacting with permeable natural fractures becomes extremely complicated with the necessity to account for conservation of fluid mass, pressure drop along natural fractures, leak-off into the formation from natural fracture walls, pressure sensitive natural fracture permeability, properties of natural fractures, fluid rheology, while tracking the interface of each region along invaded natural fracture. A main challenge is integrating this hydraulic fracture/natural fracture interaction modelling into the overall hydraulic fracture network propagating scheme without losing model effectiveness and CPU performance.
Phatak, Alhad (Schlumberger) | Kresse, Olga (Schlumberger) | Nevvonen, Olga Vladimirovna (Schlumberger) | Abad, Carlos (Schlumberger) | Cohen, Charles-edouard (Schlumberger) | Lafitte, Valerie (Schlumberger) | Abivin, Patrice (Schlumberger) | Weng, Xiaowei (Schlumberger) | England, Kevin W. (Schlumberger)
Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design which have improved productivity in these reservoirs. However, further advances in treatment design require a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and interaction with natural fractures.
This paper investigates the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters, with a focus on proppant and fluid selection. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model, with the Unconventional Production Model is presented. This workflow has shown qualitative consistency with real production data.
In this paper we applied the workflow on a realistic reservoir with characteristics from the Marcellus play, and then studied the relation between production and treatment design parameters such as proppant size, proppant concentration, the treatment volume of the treatment, fracturing fluid viscosity, pumping rate and proppant injection sequence.
Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fluid viscosity for every parameter. More than four hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design.
The behaviors observed confirm several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. Another key finding is that the optimum fluid viscosity increases with treatment volume, and decreases when pumping rate increases.