Most estimates of the resource endowment [original gas in place (OGIP)] reported for world unconventional gas start with Rogner's top-down study (Rogner 1997). That global estimate is most likely quite conservative because the oil and gas industry has discovered enormous volumes of shale gas around the world since the 1990s. The data from these new reservoirs add substantially to our understanding of the unconventional resource base. Furthermore, the uncertainty of Rogner's assessment was not quantified. Thus, considering the uncertainty, a new assessment of original unconventional gas in place worldwide is needed.The objective of this project was to estimate the probabilistic distributions of original volumes of gas trapped in coalbed, tightsand, and shale reservoirs worldwide. To accomplish this objective, we reviewed published assessments of coal and conventional and unconventional resources and established the quantitative relationship between unconventional gas [coalbed methane (CBM), tight-sands gas, and shale gas] and the conventional hydrocarbon (coal, conventional gas, and oil) resource endowments for North America. Then, we used this relationship to extrapolate original unconventional gas in place worldwide. Our assessment of the world resource endowment established an unconventional OGIP of 83,400 Tcf (P10) to 184,200 Tcf (P90), which is 2.6 to 5.7 times greater than Rogner's estimate of 32,600 Tcf.Our regional assessments of unconventional OGIP should help industry better target its efforts to rapidly accelerate the development of unconventional gas resources worldwide. The methodology used to assess the distribution of each type of unconventional OGIP may be used to estimate unconventional gas resources at the country or basin level, given knowledge of the coal in place and technically recoverable resources of conventional hydrocarbons.Review of Rogner's Assessment Methods. Rogner (1997) estimated global CBM resources by use of the distribution of coal resources and estimated values for coalbed gas content. On the bassis of Kuuskraa et al. (1992), Rogner reported that the worldwide coalbed gas resources range from 2,980 to 9,260 Tcf (85 to 262 Â 10 12 m 3 ). However, only the top 12 coal resource countries were included in the assessment. Although this initial work focused on these major coal-bearing areas, many other countries, such as Spain, Hungary, and France, have smaller but significant coal reserves and, by extension, coalbed gas resources. Thus, more countries should be included to improve Rogner's estimates.Rogner's methodology for estimating world shale-gas resources, which he states is quite speculative, assumed that shale-oil occurrence outside the US contains the US gas-in-place value of 17.7 Tcf/Gt. However, it is difficult to estimate shale-oil resources, and it is not certain that the two even correlate. Consequently, we believe an improved region-level shale-gas OGIP assessment methodology is required.Tight-sands-gas reservoirs are present in every petroleum province. In Rogner (1997...
The couple flow deformation behavior in porous media has drawn tremendous attention in various scientific and engineering fields. However, though the coupled flow deformation mechanism has been intensively investigated in the last decades, the essential controls on stress sensitivity are not determined. It is of practical significance to use analytic methods to study stress sensitivity of porous media. Unfortunately, because of the disordered and extremely complicated microstructures of porous media, the theoretical model for stress sensitivity is scarce. The goal of this work is to establish a novel and reasonable quantitative model to determine the essential controls on stress sensitivity. The predictions of the theoretical model, derived from the Hertzian contact theory and fractal geometry, agree well with the available experimental data. Compared with the previous models, our model takes into account more factors, including the influence of the water saturation and the microstructural parameters of the pore space. The proposed models can reveal more mechanisms that affect the coupled flow deformation behavior in fractal porous media. The results show that the irreducible water saturation increases with the increase of effective stress, and decreases with the increased rock elastic modulus (or increased power law index) at a given effective stress. The effect of stress variation on porosity is smaller than that on permeability. Under a given effective stress, the normalized permeability (or the normalized porosity) becomes smaller with the decrease of rock elastic modulus (or the decrease of power law index). And a lower capillary pressure will correspond to an increased rock elastic modulus (or an increased power law index) under a given water saturation.
Carbon dioxide has been used commercially to recover oil from reservoirs for more than 40 years. Currently, CO 2 flooding is the second most applied enhanced oil recovery (EOR) process in the world behind steam flooding. Water alternating gas (WAG) injection has been a popular method to control mobility and improve volumetric sweep efficiency for CO 2 flooding. Average EOR is about 9.7% with a range between 6 and 20% for miscible WAG injection. Despite all the success of WAG injection, sweep efficiency during CO 2 flooding is a typical challenge to reach higher oil recovery.We applied polymer-alternating-gas (PAG), in which polymer flooding is combined with miscible CO 2 injection, to improve the volumetric sweep efficiency of the WAG process in TR78 of the North Burbank Unit. High heterogeneity and high permeability at the top layers are the two main challenges of the North Burbank Unit. Then, we compared PAG performance with WAG and continuous gas injection (CGI). Polymer concentration and injection slug patterns were optimized during the PAG process. Simulation results show that PAG would increase oil recovery about 14.3% compared with 7.3% for WAG in TR78.This study can not only be used to guide the development of the North Burbank Unit, but also to demonstrate that encouraging recovery can be obtained in high-heterogeneity reservoirs by using PAG.
Summary Many shale gas reservoirs have been previously thought of as source rocks, but the industry now finds these source rocks still contain large volumes of natural gas and liquids that can be produced by use of horizontal drilling and hydraulic fracturing. However, one of the most uncertain aspects of shale gas development is our ability to accurately forecast gas resources and shale gas development economics. The uncertainty of the problem begs for a probabilistic solution. The objective of our work was to develop the data sets, methodology, and tools to determine values of original gas in place (OGIP), technically recoverable resources (TRR), recovery factor (RF), and economic viability in highly uncertain and risky shale gas reservoirs. Existing approaches for determining values of TRR, such as the use of decline curves or even volumetric analyses, may not be reliable early on because there may not be enough production history for decline curves to work well or the uncertainty in the reservoir properties may be too large for volumetric analyses to be useful. To achieve our research objective, we developed a computer program, Unconventional Gas Resource Assessment System (UGRAS). In the program, we integrated Monte Carlo technique with an analytical reservoir simulator to estimate the original volume in place, predict production performance, and estimate the fraction of TRR that are economically recoverable resources (ERR) for a variety of economic situations. We applied UGRAS to dry gas wells in the Barnett shale and the Eagle Ford shale to determine the probabilistic distribution of their resource potential and economic viability. On the basis of our assumptions, the Eagle Ford shale in the dry-gas portion of the play has more technically recoverable resources than the Barnett shale. However, the Eagle Ford shale is currently not as profitable as the Barnett shale because of the higher drilling costs in the Eagle Ford dry-gas window. We anticipate that the tools and methodologies developed in this work will be applicable to any shale gas reservoir that has sufficient data available. These tools should ultimately be able to allow determination of technically and economically recoverable resources from shale gas reservoirs globally.
Abstract:The oil recovery factor from shale oil remains low, about 5 to 7% of the oil in place. How to increase oil recovery from shale oil reservoirs is attracting more and more attention. CO 2 huff-and-puff was historically considered one of the best approaches to improve the oil rate. Most previous simulation studies have been based on dual porosity, but simulation results from dual-porosity models have not been as accurate as discrete fracture models in composition modeling. This study proposes a new model that integrates the embedded discrete fracture model and the dual-porosity, dual-permeability model (DPDP). The newly developed method could explicitly describe large-scale fractures as flow conduits by embedded discrete fracture modeling and could model the flow in small-and medium-length fractures by DPDP modeling. In this paper, we first introduce four different non-neighboring connections and the way to calculate the transmissibility among different media in the new model. Then, the paper compares the performance of the new method, discrete fracture modeling, DPDP modeling, and embedded discrete fracture modeling for production from oil reservoirs. Following, the paper carries out a series of simulations to analyze the effects of hydraulic fracture stages, hydraulic fracture permeabilities, and natural fracture permeabilities on the CO 2 huff-and-puff process based on the new method. In addition, the injection cycle and soaking time are investigated to optimize CO 2 huff-and-puff performance. This study is the first to integrate embedded discrete fracture modeling with DPDP modeling to simulate the CO 2 huff-and-puff process in a shale oil reservoir with natural fractures. This paper also provides detailed discussions and comparisons on the integrated strategy, embedded discrete fracture modeling, discrete fracture modeling, and dual-porosity, dual-permeability modeling in the context of fracture simulation with a compositional model. Most importantly, this study answers the question regarding how fractures affect CO 2 huff-and-puff and how to optimize the CO 2 huff-and-puff process in a reservoir with natural fractures.
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