Journal of Unconventional Oil and Gas Resources最新文献

The Haynesville Shale is one of the largest unconventional gas plays in the US. It is also one of the deepest, with wells reaching more than 10,000 ft below ground. This uncommon depth and overpressure lead to initial gas pressures of up to 12,000 psi. The reservoir temperature is also high, up to 300 °F. These pressures are uniquely high among shale gas reservoirs, and require special attention when modeling. We show that the method developed by Patzek et al. (2013) scales cumulative gas production histories of individual wells such that they all collapse onto one universal curve. Haynesville wells can take months or years for flowing tubing pressure to stabilize, so we modified the universal curve to take this delay into account. We have written a custom Pressure–Volume–Temperature (PVT) solver to calculate gas properties at the high reservoir pressure and temperature. When we apply the Patzek et al. scaling theory to 2199 individual wells in the Haynesville, we find 1546 wells have entered exponential decline due to pressure interference. We use a simple physical model to determine the time to interference, for wells with geologic parameters typical of the Haynesville, and use this time to interference to determine a field-wide stimulated permeability. Using this permeability, we arrive at an estimate of the times to interference for the remainder of Haynesville wells, and obtain production forecasts for all individual wells.

Unlike in conventional gas reservoirs, gas in shale reservoirs is stored mainly as free gas and adsorbed gas, and a small amount of dissolved gas. Well production from shale gas reservoirs usually exhibits sharply decline trend in the early period of production and then turns to long-term stable production at a relatively low rate, for which gas desorption contribution has been considered as a possible explanation.

This study aims at providing an accurate evaluation of the contribution from gas desorption to dynamic production. Through incorporation of artificial component subdivision in a numerical simulator, the production contributions of the free and adsorbed gas can be obtained separately. This analysis approach is validated firstly and then applied to two case studies based on conceptual models of Barnett and Antrim Shale. The results show that desorbed gas dominates the production in Antrim Shale, while it only plays a small role in the production in Barnett Shale. The impact of permeability and initial gas saturation are also analyzed.

In previous studies, numerical and analytical simulators were used to investigate the difference between the production performances with or without desorption, attributing the production increase to gas desorption. However, our study shows this treatment overestimates the contribution from gas desorption.

This work provides a simple but accurate method for the dynamic analysis of desorption contribution to total production, contributing to reservoir resource assessment, the understanding of production mechanisms, and shale gas production simulation.

A production type-curve solution for coalbed methane reservoirs is presented in this paper. The proposed production type curves were generated in terms of dimensionless production rate and dimensionless time groups that are based on the diffusivity equations of the two-phase flow in dual-porosity, dual-permeability coalbed methane reservoirs. The dual-porosity, dual-permeability reservoir simulation model is used as a tool in constructing the production type curves with constant sandface pressure specifications at the inner boundary. Sensitivity analyses are performed to investigate the capability of the proposed production type curves. Several sets of type-curve matching exercises are successfully performed to predict reservoir properties on different systems exhibiting a variety of reservoir and fluid properties. The proposed production type curves can be used to estimate reservoir properties including fracture permeability, fracture porosity, matrix porosity and water saturations in the fracture and matrix systems.

The effects of water presence in the coal matrix and coal shrinkage and swelling phenomena are often ignored in the production performance predictions of coalbed methane reservoirs. This paper presents the development of a new material balance formulation for coalbed methane reservoirs that accounts for water presence in the coal matrix and coal shrinkage and swelling phenomena. The development entails the governing gas and water flow equations in dual-porosity, dual-permeability coalbed methane reservoirs. Various comparative studies are conducted to investigate the capabilities of the proposed and existing material balance equations using the production data generated from a robust two-phase, dual-porosity, dual-permeability coalbed methane simulator developed at Penn State. The results show that exclusion of the two aforementioned phenomena in coalbed methane material balance formalisms reduces the estimated reservoir production capacity resulting in under-predictions of reservoir size. In addition, iterative methods for predicting production performance and average reservoir pressure using the proposed material balance formulation are developed and successfully tested against the simulation model.

Economic production from shale gas cannot be achieved by natural mechanisms alone; it requires technologies such as hydraulic fracturing in multiple stages along a horizontal wellbore. Developing numerical models for hydraulic fracturing is essential since a successful fracturing job in a shale formation cannot be generalized to another due to different shale characteristics, and restricted access to the field data acquisition. The cohesive zone model (CZM) identifies the plastic zone and softening effects at the fracture tip in a quasi-brittle rock such as shale, which leads to a more precise fracture geometry and injection pressure compared to those from linear elastic fracture mechanics. The incorporation of CZM in a fully coupled pore pressure–stress, finite element analysis provides a rigorous tool to include also the significant effect of in situ stresses in large matrix deformations on the fracturing fluid flow components, for instance leak-off. In this work, we modeled single and double-stage fracturing in a quasi-brittle shale layer using an improved CZM for porous media besides including the material softening effect and a new boundary condition treatment, using infinite elements connecting the domain of interest to the surrounding rock layers. Due to the lack of experimental data for the cohesive layer properties, we characterized the cohesive layer by sensitivity study on the stiffness, fracture initiation stress, and energy release rate. We demonstrated the significance of rock mechanical properties, pumping rate, viscosity, and leak-off in the pumping pressure, and fracture aperture. Moreover, we concluded that the stress shadowing effects of hydraulic fractures on each other majorly affects not only fractures’ length, height, aperture, and the required injection pressure, but also their connection to the injection spot. Also, we investigated two scenarios in the sequence of fracturing stages, simultaneous and sequential, with various fracture spacing and recommended the best scenario among them.

Hydraulic fracturing treatments and horizontal well technology are central to the success of unconventional oil and gas development. In spite of this success, replicated over several thousand wells over diverse shale plays, hydraulic fracturing for shale wells remains poorly understood. This includes the poor recovery of hydraulic fracture water, the inability to explain the progressive increases in produced water salinity and an incomplete understanding of the potential trapping mechanisms for hydraulic fracture water.

In this work, we focus on describing the distribution of saline water in organic and inorganic pores as a function of pore size and pore morphology with the purpose of providing fundamental insights into above questions. A kerogen model is constructed by mimicking the maturation process in a molecular dynamics simulator and it incorporates structural features observed in SEM images including the surface roughness, tortuous paths, material disorder and imperfect pore openings of kerogen pores. This work also extends this kerogen model through the use of oxygenated functional groups to study fluid behavior in partially mature shales associated with non-zero oxygen to carbon ratios.

Our results demonstrate that water entrapment mechanism and the distribution of water and ions in organic and inorganic pores are strongly related to the pore-surface mineralogy and pore width. The work in this paper also underscores the importance of kerogen thermal maturity and pore roughness on the accessibility of the kerogen material to water.

This paper presents an innovative integrated methodology and working procedure for characterizing and simulating the strong non-linear and non-stationary features caused by changes in confined pressure–volume temperature (PVT) properties over time and the pressure-dependent permeability related to inherent pore-throat size, as well as the intervened multiple porous media created by multi-stage fracture stimulation. The complicated physics behind the observed phenomena are explored. More specifically, this paper demonstrates and discusses the following: (1) a new rate-transient analysis (RTA) procedure to infer the stimulated reservoir volume (SRV) and fracture parameters; (2) the impact of the non-stationary feature, compaction effect, and pore-throat related PVT properties on the flow regime and well performance; (3) how to incorporate the non-stationary and non-linear features into the reservoir model; (4) the integrated procedure for history matching, performance forecast, and reserve assessment; (5) several field examples in the Bakken to illustrate the procedure.

The proposed procedure has been successfully applied for the following: (1) constructing the non-stationary and highly non-linear simulation models; (2) facilitating the history matching by addressing permeability reduction and PVT property variations caused by compaction and capillary pressure; (3) and ensuring more reliable performance forecasts and reserve assessments.

The study shows that the reduction of the bubblepoint pressure could be several hundred psi in the typical Bakken rock; moreover, such reduction continues following depletion via the compaction effect. The compaction effect could impair the matrix permeability by up to one order of magnitude.

The study reveals the following: (1) the confined PVT properties could widen the favored operation window, whereas the compaction effect could significantly impair the ultimate reserve of the wells; (2) the RTA-inferred SRV-related parameters are the key input for capturing the non-stationary features; (3) the impact on reserve could be over 50% without addressing the aforementioned non-stationary and non-linear issues.

This paper explores several unique phenomena in unconventional oil reservoirs which have not previously been published. The proposed analysis and assessment procedure greatly enhances the understanding of unconventional assets, and we feel it will improve the accuracy of long-term rate and reserve forecasts.