As an unconventional rock, shale contains all the features of coalbed and tight sandstone specified as gas-adsorption capacity, microscale and nanoscale porosity, and extremely low permeability. The gas-storage mechanism of shale rocks not only is dominated by free gas in macropores and natural fractures, but also is controlled by adsorbed gas in microporous organic matter (kerogen) and clay minerals. Furthermore, Darcy’s law is no longer applicable to describe gas transport in nanopores (Javadpour 2009; Wu et al. 2015). Therefore, developing a reliable model to calculate effective porosity and permeability in nanopores considering the effects of gas adsorption, stress dependence, and non-Darcy flow is crucial to characterize properties of shale-gas reservoirs and explain gas-flow behavior in nanopores.
In this study, the simplified local density (SLD) model, which has been successfully applied to analyze gas adsorption on coal, activated carbon, and shale in recent studies, is used to analyze methane-adsorption data measured from five shale-core plugs in the laboratory (Mohammad et al. 2011; Chareonsuppanimit et al. 2012; Clarkson and Haghshenas 2016). A new approach to determine the thickness of adsorbed gas dependent on the density profile of the SLD model is proposed, which in turn provides the correction of methane adsorption to pore volume (PV). Furthermore, stress-dependence effect is incorporated into the gas-adsorption effect to generate an effective porosity function in shale rocks. In addition, non-Darcy-flow effect on gas transfer in nanopores is derived from the slit-shaped pore geometry of the SLD model and is represented by a weighted sum of second-order gas slippage and Knudsen diffusion. Consequently, the effective permeability is established as a function of the effects of gas adsorption, stress dependence, and non-Darcy flow. Moreover, the functions of effective porosity and permeability are incorporated into a numerical simulator to perform history matching for gas-production data from a horizontal well with multistage hydraulic fractures in a Barnett Shale reservoir. The simulation results properly match the gas-production data at the field scale. Finally, sensitivity studies on gas adsorption, stress dependence, and non-Darcy-flow effects are conducted to investigate their contributions to evaluating and estimating gas production from shalegas reservoirs.
The results of this study suggest that gas adsorption and non-Darcy-flow effects are two competitive aspects that have major influences on shale-gas production. The developed model including gas-adsorption, stress-dependence, and non-Darcy-flow effects provides insight into the characterization of rock properties and the description of gas-transport behavior in shale-gas reservoirs.
The development of unconventional shale-gas formations in North America with horizontal multifractured wells is mature enough to identify production malpractices and abnormal productivity declines generally observed within 18–24 months of initial production. The primary objective of this study is to address all known causes of these productivity declines and to develop a fully coupled geomechanical/flow simulation model to simulate these production conditions.
This model mimics the effect of depletion-induced in-situ stress variations on short-term and long-term productivity by taking into account several phenomena, such as stress-dependent matrix and natural-fracture permeability as well as reduction in hydraulic-fracture conductivity caused by proppant crushing, deformation, embedment, and fracture-face creep. Matrix-permeability evolutions, considering the conflicting effects of non-Darcy flow and compaction, have also been accounted for in this model. Numerical solutions for simplified hydraulic-fracture planar geometries are then obtained by use of a finite-element-method scheme.
A synthetic case was defined to investigate the effects of each individual phenomenon on short-term and long-term production. Results show that the combined effects of permeability alterations in matrix and natural fractures as well as conductivity losses in hydraulic fractures may result in substantial cumulative-gas-production loss. The model also reproduces familiar field-observed trends, with lower long-term production corresponding to higher drawdowns. This behavior is attributed to the stress-dependent evolution of reservoir permeability and hydraulic-fracture conductivity. The results show that ignoring the effects of any of the previous phenomena results in overestimation of ultimate recovery. Furthermore, it is shown that proper management of pressure drawdown and the penalty for lower initial production rates in unconventional shale-gas reservoirs can yield substantially higher ultimate recovery.
The model is fully versatile and allows modeling and characterization of all widely differing (on a petrophysical level) shale-gas formations as well as proppant materials used for the stimulation treatments. This integrated model can be used for optimization of key parameters during the hydraulic-fracture design, for fine tuning production history matching, and especially as a predictive tool for pressure-drawdown management.
Saleh, Laila (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Zhang, Yandong (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
It is of major importance to analyze polymer-flooding data because they can be used to obtain screening criteria and identify where and how polymer can be best used to enhance oil recovery. However, recently published screening criteria regarding polymer flooding were based on data collected from the biannual enhanced-oil-recovery (EOR) surveys published by the Oil & Gas Journal. These data recorded valuable information for finished and ongoing polymer flooding worldwide, but they are constrained in two ways. First, they do not include some important information, such as the formation-water salinity, divalent-cation concentration, and polymer type and concentration. Second, the field data do not reflect recent polymer-technology developments that are still in the laboratory-evaluation and pilot-testing stages. To overcome these limitations, a comprehensive data set that provides the overall picture of polymer-flooding research and application is presented in this paper. In total, 865 polymer-flooding projects were considered to construct the data set, including 481 field projects from the Oil & Gas Journal (1974–2012), 329 laboratory experiments (1964–2013), and 70 pilot test projects (1966–2016) recorded in the literature. The laboratory data include porosity, permeability, oil viscosity, polymer molecular weight (MW), polymer viscosity, polymer concentration, polymer-slug size, water salinity, and divalent-cation concentration. All the data reported in this paper showed the experimental conditions that researchers used, which is consistent with the objective of our work. Our purpose is to summarize the data and tell the conditions in which polymer had been tested rather than presenting the screening criteria for polymer-flooding applications. For pilot and field tests, we only select those papers in which a project reaches or exceeds the goal of the project design. Graphical and statistical methods are used to analyze and describe the data set. The distribution of major parameters important to polymer-flooding design is presented with histograms, and the range of all parameters and their statistical values are presented with box plots. The existing data collected in this work have been statistically analyzed, resulting in some generic trends that could aid future readers in the design of a successful polymer-flooding project, such as data pertaining to the formation-water salinity, polymer MW, concentration, and polymer viscosity.
Chen, Zhiming (China University of Petroleum (Beijing)) | Liao, Xinwei (China University of Petroleum (Beijing)) | Zhao, Xiaoliang (China University of Petroleum (Beijing)) | Li, Xiaojiang (China University of Petroleum (Beijing))
Most of the work focuses on the influences of reservoir parameters on carbon-storage capacity in depleted shales, and it is very useful for selecting good candidates as repositories. Undoubtedly, the engineering parameters in shales are also very important for carbon sequestration. However, little work has discussed their impacts on carbon dioxide (CO2) storing. To improve this situation, the objective of this work is to estimate the carbon-sequestration capacity under different engineering parameters.
On the basis of a trilinear flow model, this paper studies the impacts of engineering parameters on carbon-storage potential. First, the methodology of appraising carbon-sequestration potential is introduced: (1) introducing the conceptual model, (2) developing the mathematical model, (3) obtaining the wellbore-pressure solution, (4) determining the injection time, and (5) appraising the carbon-sequestration capacity. In the conceptual model, the shale formation is divided into two subsystems and three regions: matrix subsystem, natural-fracture subsystem, hydraulic-fracture (HF) region, inner region, and outer region. With basic equations, a mathematical model is developed in these subsystems and regions. After that, on the basis of the mathematical model, CO2 storage potential in abandoned shales is investigated at different values of fracture conductivity, fracture number, fracture length, inner permeability, and wellbore length.
Although much effort has been taken to estimate the carbon-sequestration potential, little work has considered the engineering parameters. This paper innovatively estimates the carbon-sequestration capacity under different engineering parameters, which provides a guideline to selecting wells and monitoring facilities for storing CO2 in the residual-depleted shale reservoirs.
The upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach hinders effective reservoir simulation and optimization of heavy-oil recoveries by use of waterflood, polymer flood, and other chemical floods, which are inherently unstable processes. The difficulty in scaling up unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations.
Extensive experimental data in water-wet cores indicate that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named “viscous-finger number” in this paper), a combination of viscosity ratio, capillary number, permeability, and the cross-sectional area of the core. On the basis of the features of unstable immiscible floods, an effective-fingering model is developed in this paper. A porous-medium domain is dynamically identified as three effective regions, which are two-phase flow, oil single-phase flow, and bypassed-oil region, respectively. Flow functions are derived according to effective flows in these regions. Model parameters represent viscous-fingering strength and growth rates. The new model is capable of history matching a set of heavy-oil waterflood corefloods under different conditions. Model parameters obtained from the history match also have power-law correlations with the viscous-finger number. This model is applicable to water-wet reservoirs; it has not been tested for mixed-wet and oil-wet systems, low-interfacial-tension (IFT) environments, low permeability, and heavy-oil reservoirs with free gas cap.
In reservoir simulations, having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous-finger number. The model was first applied to a heavy-oil field case with channelized permeability by waterfloods. Simulation results with the new model indicated that viscous fingering strengthened the channeling. Also, the new model shows that a lower injection rate leads to a higher oil recovery. In contrast, oil recovery in waterflooding of viscous oils is overpredicted by classical simulation methods that do not incorporate viscous fingering properly. We further showed that coarse grid simulations with the new model were able to obtain saturation and pressure maps consistent with fine-grid simulations. The new model was then used to model a real field case in the Pelican Lake heavy-oil field. It was able to match the field-production data without major adjustment of reservoir/fluid properties from the literature, showing its competence in capturing subgrid viscous-fingering effects. Overall, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy-oil reservoirs, and hence can facilitate the optimization of heavy-oil enhanced-oil-recovery (EOR) projects.
Liang, Baosheng (Chevron North America Exploration and Production) | Khan, Shahzad A (Chevron North America Exploration and Production) | Puspita, Sinchia Dewi (Chevron North America Exploration and Production)
It is important to determine several key parameters, such as well spacing, completions design, landing strategy, and pad sequence, for a successful full-field development of the unconventional reservoir that involves multiple wells and pads in a given area of interest. Those parameters are normally considered individually through small and simple models. In this paper, focusing on developing the whole area effectively, we provided a systematic work flow to handle such challenges together: We first recommended a top-down concept that better represents actual field development and illustrates the importance of the 3D Earth model for the unconventional reservoir; we then proposed an integrated modeling that is an iterative loop consisting of the 3D Earth model, hydraulic-fracture modeling, reservoir simulation, and uncertainty analysis.
It is uncommon to build a 3D Earth model for the unconventional reservoir mainly because of the lack of data and software capability. In this paper, we provided a cost-effective approach for the first time on the basis of a large amount of existing vertical wells, newly drilled horizontal wells, and all the data available. A 3D Earth model by use of approximately 1,100 vertical wells from the Midland Basin was presented. Such a model has a high resolution conditioned by high well density, and has an advantage of capturing hetrogeneities and interactions more than a simplified model created either from one well or low-resolution seismic interpretation. The model was fed into hydraulic-fracture modeling with the consideration of natural-fracture network and stress shadow, followed by reservoir simulation. The in-house uncertainty-analysis package that functions by experimental-design philosophy is linked to the Earth model, hydraulic-fracture modeling, and reservoir simulation. For the first time, the impacts of all the parameters together were evaluated through the final production performance. In our example, we considered completions design, discrete-fracture-network (DFN) characterization and generation, unpropped hydraulic-fracture properties, fracture compaction, and matrix permeability. The result indicated that DFN characterization is the most important parameter affecting production performance.
We applied our model and work flow to field development. Well spacing and pad sequence were studied in this paper as two examples. We demonstrated that it is important to properly consider complex interactions among multiple clusters, stages, and wells to evaluate the impacts on well spacing, completions, and development sequence.
Tietze, Kristina (Deutsches Geoforschungszentrum Potsdam) | Ritter, Oliver (Deutsches Geoforschungszentrum Potsdam) | Patzer, Cedric (Deutsches Geoforschungszentrum Potsdam) | Veeken, Paul C. H. (Wintershall Holding GmbH) | Verboom, Bert (Wintershall Holding GmbH)
Production from oil fields requires the monitoring of hydrocarbon saturation in the reservoir. In the Bockstedt oil field there exists a substantial difference in resistivity between an oil-filled (approximately 100–16 Ω·m) and a brine-filled (0.6 Ω·m) reservoir. Controlled-source electromagnetics (CSEM) is chosen to test whether sufficient resistivity differences can be observed by means of surface measurements. The target is a Lower Cretaceous clastic interval at an approximate depth of 1200 m. Forward modeling demonstrates that the expected resistivity changes at reservoir level cannot be resolved with a survey setup of only surface electrical sources and sensors. Therefore a borehole-to-surface technique has been developed, whereby the metal casing of an abandoned production well serves as an input electrode. CSEM surveys were acquired in 2014 and 2015 as a time-lapse baseline and monitor for both horizontal electric (Ex and Ey) components. A four-transmitter and 25-receiver configuration was deployed for these surveys. Forward modeling indicates that induction effects from metal objects, such as casings of production wells, cannot be ignored in the electromagnetics (EM) modeling. A shallow observation well was drilled in 2015 to make the collection of vertical electric field (Ez) data sets possible. A new downhole sensor was developed for this purpose. Numerical simulations suggest Ez data are more sensitive to the anticipated resistivity changes in the reservoir. Because Ez is two orders of magnitude smaller than the horizontal components, verticality is of great importance to avoid masking the Ez signal by interference from unwanted horizontal components. Similar acquisition parameters are adopted for 2014 baseline and 2015 monitor surveys to facilitate the comparisons. The repeatability is good, generating comparable response functions. A new, computationally efficient approach considers the effect of the metal casings, and is implemented in the 3D modeling and inversion codes. Preliminary resistivity models obtained from 3D CSEM inversion explain the observed data, and are in agreement with results from a 3D-seismic survey and resistivity logs in the calibration wells. Incorporation of the metal casings in the EM-modeling scheme increases the lateral continuity of inverted resistivity bodies. In November 2016, a new time-lapse acquisition campaign was undertaken to collect a second Ex/Ey monitor and the first monitor survey for the Ez component.
Foam has been successfully used in the oil industry for conformance and mobility control in gas-injection processes. The efficiency of a foam-injection project must be assessed by means of numerical models. Although there are several foam-flow models in the literature, the prediction of foam behavior is an important issue that needs further investigation. In this paper, we estimate foam parameters and investigate foam behavior for a given range of water saturation by use of two local equilibrium foam models: the population balance assuming local equilibrium (LE) model and the University of Texas (UT) model. Our method uses an optimization algorithm to estimate foam-model parameters by matching the measured pressure gradient from steady-state foam-coreflood experiments. We calculate the effective foam viscosity and the water fractional flow by use of experimental data, and we then compare laboratory data against results obtained with the matched foam models to verify the foam parameters. Other variables, such as the foam texture and foam relative permeability, are used to further investigate the behavior of the foam during each experiment. We propose an improvement to the UT model that provides a better match in the high-quality regime by assuming resistance factor and critical water saturation as a linear function of the pressure gradient. Results show that the parameter-estimation method coupled with an optimization algorithm successfully matches the experimental data by use of both foam models. In the LE model, we observe different values of the foam effective viscosity for each pressure gradient caused by variations of foam texture and the shear-thinning viscosity effect. The UT model presents a constant effective viscosity for each pressure gradient; we propose the use of resistance factor and critical water saturation as a linear function of the pressure gradient to improve the match in the high-quality regime, when applicable.