Production Analysis Case Study
Introduction
Gas shale can be defined as any tight, fine-grained, organic-rich, gas self-sourced sedimentary formation. Gas shale contains all elements of a petroleum system and is a source rock, which provides hydrocarbons. As high as fifty percent of gas by weight can be formed through the maturation of organic material within the shale. The generated gas is trapped within shale adsorbed in the organic/clay material or free inside pores. As shale is relatively impermeable and the rate of hydrocarbon generation far exceeds the rate of outflow, hydrocarbons accumulate within shale formations. Thus, unconventional shale will trap most of the gas/oil in spite of their high pressure due to the low permeability.
Shale has nanoscale pores with dimensions ranging from several nanometers to few micrometers. Due to the nanoscale pores, the flow regime in the shale matrix is defined by slip flow and transition flow (Fig. 1). Hence, the Darcy flow model is not applicable to the shale rock matrix, and the shale permeability is expected to be in the order of nano-Darcy. However, Darcy flow occurs both in the open natural fractures and fissures and in the induced fractures of the shale formation.
Fig. 1
Flow regimes as per Knudsen in the microscopic porous medium
As shale gas reservoirs are very tight, they have to be drilled horizontally to produce economically. Large fractures must be created along these horizontal wells to produce commercially from shale gas reservoirs. The geometry of the created fracture(s) depends on many variables, including the pumping rate and pressure, pad volume, fluid viscosity, proppant concentration, in situ stress, and rock fabric. Ideally, a fracture grows in the same plane as the well in both length and height and can reach other formations with higher in situ stress barriers. A fracture continues to grow in length until the end of the pumping treatment. The resulting fracture is planar and extends in a bi-wing manner away from the wellbore. Hence, they are normally called bi-wing, planar, or simple fractures. Other fracture geometries may occur due to many reasons, including the existence of natural fractures and low-stress anisotropy. Due to micro-seismic activities, four possible fracture geometries can be present in hydraulically fractured reservoirs. As the performance of a well in shale reservoirs is highly influenced by the geometry of the fractures created and the hydraulic fracture signal is inseparable from the reservoir signal, it is essential to understand the complexity of the fractures. Moreover, a complex fracture geometry is sought in stimulation treatment because it not only connects more rock surface area to the wellbore but also enhances the effective permeability of the reservoir by activating more natural fractures and fissures. Such a complex fracture geometry is identified as a stimulated reservoir volume (SRV). Although the effect of an SRV on a conventional reservoir is minor, it is significant in shale gas reservoirs. Gomaa et al. have shown that the fracture complexity can be controlled by controlling the viscosity of the fracturing fluid. SRV creation can extend far beyond the induced fractures, and this can be detected from the micro-seismic activities. An SRV is created when the fracturing water is imbibed by the high capillary shale, preventing fractures from closing and acting as a conduit for the hydrocarbons to flow to the induced fracture. Other studies have also examined the role of the fracture fluid in determining the extent of production. Only quarter to half of the pumped fluid is recovered in shale stimulation operations, with the rest of the fluid remaining trapped in the reservoir. In actual practice, it is generally considered a bad sign to recover more stimulation treatment fluid.
Published reports indicate that researchers have extensively studied and modeled the effects of adsorption of shale gas and coalbed methane. Fan et al. have shown that the micropores highly affect the gas adsorption in shale gas reservoirs. The approach they used will help better estimate the gas content in shale gas reservoirs. Zhao et al. have shown that there is a critical pore size that affects the adsorption of coalbed methane during the water injection process. Wang et al. have studied the effects of the competitive adsorption of methane and carbon dioxide on the adsorption of shale gas. They found that the organic pores (pores in organic matter) have a higher adsorption capacity for CO2 compared to methane although the self-diffusion of methane is larger than that of CO2. In addition, they indicate that the direction, i.e., whether the adsorption is horizontal or vertical, has a major effect on the adsorption capacity. Horizontal adsorption is higher than vertical adsorption.
Many empirical, analytical, and numerical solutions to analyze production data in porous formations are available in the published literature. Arps was the first to analyze declining rates in producing wells empirically. His models predict the future rate and the expected ultimate recovery (EUR) based on the production history of the wells as long as the production is stable and a BDF (boundary dominated flow) has prevailed. In shale formations, transient flow typically lasts for years and the application of Arps's equations during this period tends to overestimate future production. Conventional well test analysis methods are currently used to analyze the production from shale gas reservoirs. Well test analysis requires long shut-in periods to analyze shale, and this method is not practical because of the unavailability of suitable shut-in periods. Hence, rate transient analysis is more commonly used to analyze shale reservoirs. Other methods have been suggested for the analysis of production from shale such as diagnostic analysis of production data, deterministic workflow, and a generalized workflow that incorporates all transient analysis methods.
The amount of gas held in shale gas sources exceeds that of conventional reservoirs. Commercial production of gas from unconventional resources has been made difficult due to many technical challenges. The advances in drilling and hydraulic fracture treatment have helped enhance the recovery by exposing more of the reservoir to the wellbore. However, production analysis leads to a non-unique solution for parameters such as the fracture half-length and permeability due to the lengthy transient period that a shale reservoir expresses.
A unified workflow for the analysis of the gas production from unconventional resources is not available in the literature, and all the previous analyses are subjective and depend on the analyzed cases. Until now, there is no single systematic approach in designing stimulation treatments for the shale gas reservoirs. Treatment parameters (such as lateral length, number of stages, and the conductivity of fracture) are subjective. In addition, there is high uncertainty in estimating reservoir and stimulation parameters such as permeability, initial pressure, and fracture half-length. The novelty in this study includes the integration of initial production analysis, probabilistic evaluation, and sensitivity analysis for the first time. The proposed workflow consists of various approaches that fits different data sets. Therefore, it can be easily generalized and applied to any shale gas play.
The objective of this paper is to evaluate the key parameters of reservoirs and wells that affect shale gas production. Reservoir parameters such as porosity, permeability, and the initial reservoir pressure will be evaluated. The completion parameters that will be investigated are well spacing, well length, fracture geometry, etc. Finally, an integrated production analysis workflow will be developed to be used as a guide for the production analysis from shale gas reservoirs.