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Abstract Many fractured shale/tight gas wells exhibit the bilinear flow regime during early stages of their production lives. This flow period has a potential to reveal important information about fractures of shale wells. Although many valuable data can be extracted from this early production period, current analytical equations for the bilinear flow period are particularly inaccurate for gas wells. This inadequacy can be explained with the fact that these equations do not correct for the rate dependency of bilinear flow. Thus, to address this problem and to model the bilinear flow regime in the gas wells accurately, we present a new correction factor that accounts for this rate dependency. It is widely accepted that the use of the real gas pseudo-pressure is usually sufficient to correct the nonlinearity present during the radial flow. However, the real gas pseudo-pressure does not correct the nonlinearity present during the linear flow. Although a number of authors have developed methods to correct the errors caused by the gas nonlinearity during the linear flow period (Ibrahim and Wattenbarger, 2006; Nobakht and Clarkson, 2012), currently there are no studies to correct the errors during the bilinear flow regime. To bridge this obvious gap, we develop a new correlation that accounts for the nonlinearity present during the bilinear flow. One of the advantages of the proposed approach is that our correction factor can be combined with already developed bilinear flow equations to improve the fracture analysis. This improvement is essential for better understanding, description, and optimization of the shale wells. Additionally, we demonstrate the specifics of the application and significance of our new correlation with a synthetic as well as field examples. Judicious application of our novel correction approach improves the accuracy of the shale gas well analysis. Introduction Worldwide shale formations are a significant and abundant source of natural gas. Although shale gas was first produced in the 1820s from a very shallow formation in Fredonia, New York (), it has not been produced in commercial quantities until almost two centuries later. The shale gas industry, as we know it today, started with the development of horizontal well drilling and multi-stage hydraulic fracturing in the late 20th century. At that time shale gas production was still relatively small. However, it boomed in 2005 because of rapid improvements in the rock fracturing techniques and drilling technology (Figure 1).
- North America > United States > Texas (0.29)
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > New York (0.24)
- Europe > Norway > Norwegian Sea (0.24)
Summary Unconventional fractured gas wells occasionally exhibit bilinear flow during early production. When this flow regime is observed, important fracture properties can be estimated such as conductivity and/or spacing. However, the application of present-day rate-transient-analysis (RTA) methods to bilinear flow results in up to 18% error. This error is rate-dependent, and occurs because of nonlinearities in the gas-diffusivity equation. This paper presents a new correction factor that handles the rate dependency of bilinear flow, and enables more-accurate reservoir characterization. The diffusivity equation of gas in porous media has some nonlinearities that cannot be addressed by only using the real-gas pseudopressure. Even though neglecting these nonlinearities results in a model that is sufficiently accurate for the radial-flow case, errors arise in the boundary-dominated-flow (BDF) (Fraim and Wattenbarger 1987), the linear-flow (Ibrahim and Wattenbarger 2006; Nobakht and Clarkson 2012), and, as shown in this article, the bilinear-flow cases. Currently, no research studies provide an accurate bilinear-flow analytical model for gas reservoirs. To bridge this gap and to provide rate-transient analysts with a practical tool, this work presents a correction factor that can be incorporated into the existing bilinear-flow models. The correction factor was developed following an approach similar to that of Ibrahim and Wattenbarger (2006). The first step was to simulate a number of reservoir and well conditions. Second, fracture properties were back calculated with the current bilinear-flow models. Finally, errors between the back calculated and the simulated properties were correlated to dimensionless drawdown. After these steps, a correction factor was obtained that applied to various bilinear-flow cases. The obtained numerical results indicate that errors in bilinear-flow models are correlated with rate, or more precisely, dimensionless drawdown [a similar behavior is observed in the analytical model of linear flow, as demonstrated by Ibrahim and Wattenbarger (2006)]. This correlation can be used to reduce error to less than ยฑ3%. Because the simulated cases cover an extensive range of unconventional-reservoir conditions, the empirical correction is robust and applicable to a wide variety of reservoir conditions. Most importantly, the correction is practical and can be readily incorporated into existing bilinear-flow models. The application of the new correction is demonstrated in this article with synthetic and field examples.
- North America > United States (1.00)
- North America > Canada (0.68)
- Asia > Middle East > Saudi Arabia (0.68)
Abstract Many shale wells undergo a gradual production decline before reaching a linear flow decline. This gradual decline lasts for several days and often matches a quarter-slope. Some authors attribute this gradual decline to bilinear flow, which occurs as a result of simultaneous linear flow in natural fractures and matrix (Al-Ahmadi and Wattenbarger 2011; Tivayanond et al 2012). In this paper, we show that bilinear flow in natural fractures and matrix is short and, therefore, it cannot explain the sustainable gradual decline observed in shale wells. Instead, we provide two alternative explanations. Bilinear flow caused by low-conductive hydraulic fractures is one explanation. Another one is an artificial shift in data caused by ignoring flowback. First, we use analytical solutions and show that bilinear flow is short unless matrix permeability is extremely low or natural-fracture spacing is very large. Second, we show that analytical solutions are unrealistic when natural fracture spacing is large. Third, we use reservoir simulation to obtain more realistic results and show that bilinear flow in matrix and natural fractures is not sustainable. In conclusion, we show that ignoring flowblack data results in a fictitious quarter-slope and demonstrate the concept with field examples. This work shows the importance of including flowback data into rate transient analysis. In addition, it describes a procedure to accurately analyze production data and avoid misleading bilinear flows. Several sensitivity studies are also shown to define the geometrical and petrophysical conditions under which the bilinear flow regime is not expected. Concepts presented in this paper provide engineers with better tools for analyzing and forecasting production from shale gas wells.
- Asia > Middle East > Saudi Arabia (0.68)
- North America > United States > Texas (0.48)
- Asia > Middle East > Kuwait > Al Ahmadi > Al Ahmadi (0.26)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Oklahoma > Arkoma Basin > Fayetteville Shale Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Cana Woodford Shale Formation (0.99)
- North America > United States > Arkansas > Arkoma Basin > Fayetteville Shale Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract There are many mathematical models for production data analysis of shale wells. Certain models assume a set of parallel hydraulic fractures perpendicular to a horizontal well. Some of these models include natural fractures perpendicular to the hydraulic fractures. In these models, there is uncertainty in whether transient linear flow is dominated by fractures or matrix. Identification of the medium in transient flow usually requires assuming fracture properties. In this paper, we introduce an identification method which does not require explicit knowledge of fracture properties. This work also helps forecast wells which have not reached boundary dominated flow decline. The paper focuses on four fracture distribution models that could describe shale wells. We introduce the identification procedure to determine the true fracture distribution model for a region. Once the model is identified, it is possible to determine whether linear flow is dominated by matrix or fractures. Identification of the true model can also improve forecast accuracy. The model identification procedure is based on the assumption that rock and fluid properties are similar within the region of interest. Shale wells often exhibit long transient linear flow. Forecast projection is uncertain because the end of linear flow cannot be calculated without knowledge of fracture properties. The model identification procedure presented here enables more accurate production forecast and analysis. In addition, model identification might help optimize fracture design for future wells. This work reduces uncertainty and eliminates inapplicable models.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.96)
Abstract Fractured reservoirs present a challenge in terms of characterization and modeling. Due to the fact that they consist of two coexisting and interacting media: matrix and fractures, not only we need to characterize the intrinsic properties of each medium but also accurately model how they interact. Dual-porosity models have been the norm in modeling fractures reservoirs. However, these models assume uniform matrix and fractures properties all over that medium. One further step into capturing the reservoir heterogeneity is to subdivide each medium and assign each one different property. In this paper, fractures are considered to have different properties and hence the triple-porosity model is introduced. The triple-porosity model presented in this paper consists of three contiguous porous media: a matrix, less permeable microfractures and more permeable macrofractures. These media coexist and interact differently in the reservoir. It is assumed that flow is sequential following the direction of increased permeability and only macrofractures provide the conduit for fluids flow. Different solutions were derived based on different assumptions governing the flow between the fractures and matrix systems; i.e., pseudosteady state or transient flow in addition to different flow geometry; i.e., linear and radial. Some of these solutions are original. The model was confirmed mathematically by reducing it to dual-porosity system and numerically with reservoir simulation and applied to field cases. In addition, the solutions were modified to account for gas flow due to changing gas properties and gas adsorption in fractured unconventional reservoirs.
- North America > United States > Texas (0.94)
- Asia > Middle East > Saudi Arabia (0.68)