This paper sheds light on the nonlinear physics involved in the production of shale-gas reservoirs by improving the understanding of the complex relation between gas production, reservoir properties, and several treatment-design parameters. The authors ran 28 simulations to cover the 2D parametric space of proppant size and fracturing-fluid viscosity for a range of parameters (detailed in the complete paper). More than 1,400 simulations were run in this parametric study, and the results provide guidelines for optimized treatment design.
Introduction
Production from shale-gas reservoirs depends greatly on the efficiency of stimulation. The accumulated experience in our industry with the technique of hydraulic fracturing has led to best practices in treatment design that have contributed to the rapid increase in productivity of shale-gas wells over the last decade.
The objective of this paper is to present a parametric study on the relation between the parameters of a treatment design and the production outcome based on numerical simulation. To generate an extensive number of simulations, the workflow is automated with a script that sequentially runs all the simulation cases, archives the results, generates visualization outputs, and creates a simulation report. This method enables more than 100 simulations overnight, depending on the complexity of the cases.
The methodology used in this study begins with constructing a base case built from the Marcellus shale data. The outputs for each set of simulations are accumulated production after 6 months, 1 year, and 3 years; total propped length and average propped conductivity are regarded as a function of both proppant size and fluid viscosity. A total of 1,467 cases was simulated for this parametric study (see the complete paper for a full discussion of results of these simulations).
Base Case
For the base case of this parametric study, permeability is 200 nd and the horizontal stress anisotropy is 1%. The conductivity of unpropped fractures is fixed at 0.001 md-ft. The completion is a horizontal well, and the base case is a single stage of pumping through four perforation clusters that are 100 ft from each other.
The treatment is made up of 224,576 gal of fracturing fluid and 183,700 lbm of proppant pumped at 80 bbl/min. The schedule begins with 18% of pad followed by slurry with a proppant concentration of 1 ppa. For simplicity, the fracturing fluid is assumed to have Newtonian rheological behavior.
The natural-fracture network consists of fractures that are 200 ft in length on average and spaced 200 ft apart on average, as illustrated in Fig. 1. The natural fractures are considered to be vertical, extending through all three zones. The production is simulated at a constant bottomhole flowing pressure of 1,000 psi.
Modeling Assumptions
The hydraulic-fracture simulation in this study uses the following assumptions:
- The fracture height is fixed, considering that it is contained within the three zones. This assumption disables the coupling between height growth and stress shadow that is highly nonlinear.
- To reduce the computational time, the shut-in period at the end of treatment was not simulated in this study. This assumption was made because it has been established previously that simulating the shut-in time did not modify the production forecast significantly.
- The model does not account for any reduction of proppant-pack permeability caused by mixing of different-sized proppants.
- The model does not account for the effect of temperature on the rheology of the fracturing fluid.
The production simulation in this paper uses the following assumptions:
- It considers only single-phase flow (gas).
- Even though the fracturing simulator provides a detailed vertical profile of the reservoir and fracture properties, the production model uses averaged values in the vertical direction.
- The model considers linear flow from the matrix to the fracture. Therefore, the radial flow at the fracture tip is not modeled accurately.
- The model does not consider flow between matrix blocks, meaning that when the matrix blocks are depleted significantly, the calculated flow rate from the matrix blocks to the fractures is an approximation.
- The conductivities are kept constant during the production simulation and do not account for variation of the pressure during production.
Pumping Schedule
Proppant Size. The size of the proppant and proppant concentration impact proppant placement and fracture geometry in several ways.
- Larger proppants of the same density have higher settling velocities and therefore settle closer to the wellbore.
- Proppant banks made of large proppants are more difficult to erode.
- Large proppants bridge more easily.
- The proppant concentration increases the apparent viscosity of the slurry, increasing the average width of the fracture and reducing the fracture length.
- Small proppants are carried farther and increase the chance of tip screenout.
Fracturing-Fluid Viscosity. The viscosity of the fracturing fluid has a major impact on both the width and the length of hydraulic fractures. The greater the viscosity, the greater the width and the shorter the fracture length. In our base case, the fracture has a fixed height, but for cases with no vertical containment and height growth, greater viscosity also translates into greater fracture height.
At low viscosity (1 cp), the high settling velocity and accumulation of a proppant bank provide greater proppant concentration per surface area, despite the small fracture width. On the contrary, for high-viscosity fluids (100 cp), the settling is negligible, but the large fracture width also provides a greater proppant concentration per fracture-surface area. In between, the fracturing-fluid viscosity of 10 cp gives a more-diluted proppant placement and lower averaged propped conductivity.
Pumping Rate. The pumping rate is a parameter that influences several mechanisms of the hydraulic-fracturing process. It controls the net pressure, and therefore the fracture growth, especially in case of high horizontal stress anisotropy. It also impacts proppant placement, influencing the settling, the leakoff, and the chances of bridging.
The first observation is that the maximum production increases slightly with pumping rate. The second observation is that the area of optimum production (see Fig. 21 in the complete paper) increases and spreads toward lower fluid viscosity with an increase in the pumping rate. Therefore, it appears that the pumping rate has little impact on the production from treatments with viscous fluids (more than 5 cp), but influences significantly the production from treatments with low viscosity. Only the treatments with low-viscosity fracturing fluid are sensitive to variations of the pumping rate. The study also shows that the production from slickwater treatments steadily increases as the pumping rate increases. This result confirms the common best practice of maximizing the pumping rate for slickwater treatments.
To illustrate the impact of pumping rate, we can compare the propped-fracture-conductivity profile for the same pumping schedule consisting of 40/70-mesh sand and slickwater (1 cp), but with two different pumping rates (40 and 120 bbl/min). The first observation is that the size and shape of the hydraulic-fracture network is not significantly modified by the variation of the pumping rate. However, the proppant is placed deeper into the fracture network when a higher rate is used. The reason is that, at low rate, for the same volume of fluid, the duration of the treatment is increased and the fluid velocity is reduced. Therefore, there is more settling of the proppant during the treatment.
Reservoir Properties
Reservoir Permeability and Unpropped Conductivity. The permeability of the reservoir influences both the fracturing and the production from the reservoir. The fracturing controls the leakoff effect of the fracturing fluid into the formation. The permeability also controls production rates, in particular those of tight reservoirs. But why do treatments designed for tight reservoirs differ from those for conventional reservoirs?
Production increases when the permeability increases. A second observation is that the shape of the optimum area (see Fig. 32 in the complete paper) is similar for all three cases, but the optimum viscosity seems to decrease as the permeability increases.
Our explanation for the decreasing optimum viscosity as a function of the reservoir permeability can seem counterintuitive because conventional treatments for higher-permeability reservoirs use higher-viscosity fluids (linear gels and/or crosslinked gels) and higher proppant sizes. In our base case, the proppant concentration is lower (1 ppa) than for conventional treatments and thus increases the risk of having partial monolayers of proppant, the conductivity of which is greatly diminished under stress conditions because of excessive crushing. In these conditions, increasing proppant settling is the most-effective way to maintain sufficient conductivity. To validate this explanation, the same parametric study on the reservoir permeability was conducted, but with twice the amount of proppant.
An initial observation is that the optimum viscosity for 6 months and 1 year is not declining, but is constant as the permeability increases. The optimum viscosity at 3 years first declines, then increases, but the analysis of the simulation shows that at 2 ppa, the area of optimum production after 3 years seems to stretch between two optimum designs, making it difficult to define an absolute optimum viscosity. The second observation is that the optimum proppant size seems to increase with the reservoir permeability, meaning that indeed there is less risk of weak-partial-monolayer development and that larger proppant sizes (20/40‑mesh sand) can contribute to increasing fracture conductivity.
There is a relationship between production and unpropped conductivity as a function of reservoir permeability, propped conductivity, proppant placement, and network complexity. Our base case considers a relatively low residual conductivity of hydraulic fractures without proppant (0.001 md-ft), which highlights the importance of proppant placement and propped conductivity. In reality, this unpropped conductivity can vary by several orders of magnitude, depending on several parameters such as formation properties, the size and distribution of asperities, the degree of fracture displacement, and rock-mechanical properties.
Horizontal-Stress Anisotropy. This parameter is defined as the difference between the maximum and the minimum horizontal stress, and is modified by increasing the maximum horizontal stress. The horizontal-stress anisotropy is a negligible parameter for biwing fractures but is an essential parameter for generating complex fracture networks. If a hydraulic fracture tends to propagate toward the maximum-stress direction (the path of least resistance), once it reaches a natural fracture that is oriented in a different direction, the hydraulic fracture needs to build up additional pressure in order to open the natural fracture and resume propagating. This additional pressure is a function of the stress anisotropy and the orientation of the natural fracture. Therefore, the question is how this mechanism influences the proppant placement and the production. Our study shows that the production decreases as the stress anisotropy increases.
To understand the reasons for this production decline, Fig. 2 compares the proppant concentration for the same treatment but with low and high stress anisotropy (0.5 and 6%, respectively). It shows that for the low stress anisotropy, the hydraulic-fracture network is larger and the proppant is placed deeper into the network. However, the proppant concentration is greater in the case of high stress anisotropy.
Horizontal Stress-Field Orientation. This parameter is defined by the angle between the maximum-stress direction and the direction of the well. The horizontal field orientation will define in which direction the hydraulic fracture will propagate, searching for the path of least resistance, toward the maximum-stress direction. Horizontal wells are typically drilled in the direction of the minimum stress, so hydraulic fractures propagate orthogonally to the well.
Fig. 3 shows the proppant concentration of a slickwater treatment with 40/70-mesh sand for maximum-stress angles of 30 and 75°, and also illustrates that the spacing between fractures reduces as the angle decreases.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16400, “Analysis of the Impact of Fracturing-Treatment Design and Reservoir Properties on Production From Shale-Gas Reservoirs,” by C.E. Cohen, C. Abad, X. Weng, K. England, A. Phatak, O. Kresse, O. Nevvonen, V. Lafitte, and P. Abivin, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.