Journal of Unconventional Oil and Gas Resources最新文献

In this study, we developed a methodology for identifying the critical variables needed for accurate planning of a hydraulic fracturing treatment in a shale resource play where much of the properties required for hydraulic fracture modeling remain unknown. The critical variables identified can thereafter be used to develop a proxy model that can be used in lieu of a numerical simulator.

This study was conducted in two stages. In the first stage, we used 2-level fractional factorial designs and a pseudo-3D simulator to identify the most important variables affecting the simulated fracture geometry. The variables investigated included geologic, mechanical and treatment design parameters. Using the three most significant variables for each fracture geometry component identified from the first stage, the second stage of this study applied Box-Behnken experimental design and response surface methodology to quantify functional relationships between input variables and the fracture geometry. These proxy models, typically polynomial equations, can be used to predict the fracture geometry with very little computational time.

The use of experimental design drastically reduces the number of simulations required to evaluate large number of variables. With only 137 simulations, 26 variables were ranked based on their statistical significance and non-linear proxy models were developed for the nine fracture geometry variables. Predicted values of the fracture geometry using the proxy models were in good agreement with the simulated values (R² value of 0.99 for fracture length and fracture height and R² value of 0.96 for fracture width). These linear and non-linear proxy models were validated by comparing the results from the proxies and the actual simulator using a random value dataset within the design space. The results indicate a good match for the width at the top and bottom of the fracture and propped fracture height/length. Engineers can use the results described here for quick estimates of fracture dimensions and the methodology outlined here can be used with more complicated fracturing models.

Is it the quality of the formation or the quality of the completion that determines or controls the productivity of a shale well? In this paper we attempt to address this important question. We present a case study using a fit-for-purpose approach with no attempt to generalize the final conclusions. The analysis presented in this article is based on field measurements. No assumptions are made regarding the physics of the storage and/or the transport phenomena in shale. Our objective is to let the data speak for itself.

The case study includes a large number of wells in a Marcellus shale asset in the northeast of the United States. Characteristics such as net thickness, porosity, water saturation, and TOC are used to qualitatively classify the formations surounding each well. Furthermore, wells are classified based on their productivity. We examine the hypothesis that reservoir quality has a positive correlation with the well productivity (wells completed in shale with better reservoir quality will demonstrate better productivity). The data from the field will either confirm or dispute this hypothesis.

If confirmed, then it may be concluded that completion practices have not harmed the productivity and are, in general, in harmony with the reservoir characteristics. The next step in the analysis is to determine the dominant trends in the completion and judge them as best practices. However, if and when the hypothesis is disproved (wells completed in shale with better reservoir quality will NOT demonstrate better productivity), one can and should conclude that completion practices are the main culprit for the lack of better production from better quality shale. In this case, analysis of the dominant trends in the completion practices should be regarded as identifying the practices that need to be modified.

Results of this study show that production from shale challenges many of our preconceived notions. It shows that the impact of completion practices in low quality shale are quite different from those of higher quality shale. In other words, completion practices that results in good production in low quality shale are not necessarily just as good for higher quality shale. Results of this study will clearly demonstrate that when it comes to completion practices in shale, “One-Size-fit-All” is a poor prescription.

Phosphate ore body is an important basis for food supplies and the fine phosphorus chemical industry. With underground mining of the Ph₃ seam of Xiongjia Gulf Phosphate ore stope in China as a research background, the excavation process is simulated using the Hoek-Brown model in this paper. Hoek-Brown parameter selection method is proposed first, and the influence of the goaf adjacent to this seam and the rock movement caused by underground mining, pillar yield and surface subsidence deformation are then studied. Finally, the feasibility of implementing a room-and-pillar mining system in the gently inclined phosphate ore body is analyzed. It is pointed out that local ground subsidence should cause enough attention.

Relative permeability is one of the main petroleum recovery controller that is a function of porous media and the reservoir fluid. Water flooding titled as one of the eldest EOR methods is still used in some of reservoirs. For proper perception and description of rheology in reservoir scale, knowing the flowing fluid processes specifications and mechanisms and also recognition of porous media type in pore-scale is necessary. In this way, the new age has arrived in reservoir study by introducing porosity model on glass. We can have the two-dimension porous media in actual size by designing a microfluidic chip. This article implies the effects of heterogeneity on relative permeability curves by micro model system and water flooding. High definition photos from different water and oil saturations and also Goodyear equations are used for analyzing the effects of heterogeneity on water and oil permeability in pore-scale. In conclusion, it is observed that in glass micro model oil and water relative permeability curves are dependent on porous media pores sizes. So that as much as these pores grows, the relative permeability will be increased. Moreover, pores sizes distribution and direction have effects on relative permeability.

In this paper, a novel method which integrates the microseismic events (MSE) and well production data is introduced for calibrating the fracture networks. The fracture geometry is calibrated by matching the MSE with an L-system which is based on the fractal geometry theory. Integer programming shows a vigorous performance during the geometry matching procession. The matching fractal networks can cover most MSE and follow the extending trend of the original fracture networks. Furthermore, the multilevel feature of the fractal networks helps to specify the properties of the fractures for a meticulous study. Calibration on properties, especially the fracture half-length and the fracture conductivity, is carried out according to the geometry matching results. Rate transient analysis (RTA) is utilized for interpreting the production data and estimating the parameters of the fracture networks; well production data is taken as the matching object to validate and adjust the fracture properties. The results show that when considering a complex fracture network, estimation through traditional RTA may not reflect the properties of the total fracture network: (1) the estimated fracture half-length equals to the total half-length of the main fractal fractures, which determines the initial production and decline rate; (2) the estimated fracture conductivity characterizes an average conductivity of the secondary fractures which cover most stimulated region.

Gas-shales are gas bearing organic-rich mudstone with extensive natural fractures. Matrix permeability is typically in the region of 10⁻⁴ mD or less, and pore throat sizes are in the vicinity of 100–1000 nm. Consequently, stimulation is required to achieve economic gas recovery rates. Horizontal wells combined with successful multi-stage hydraulic fracture treatments are currently the most established method for effectively stimulating such formations.

The injected fracture fluid typically contains 1–7% KCL for the purpose of clay stabilization. However chemical analysis of the flowback water shows that it contains 10–20 times more dissolved solids than the injected fluid; total dissolve solids (TDS) can be as high as 197,000 mg/L with chloride levels alone being as much as 1,510,000 mg/L (Haluszczak et al., 2013).

This paper outlines the development and validation of a fully implicit fluid transport and halite dissolution numerical model that is used to predict and analyze the ionic compositions of flowback water from hydraulically fractured shale formations. The simulator is designed to predict the concentration of Na⁺ and Cl⁻, which are the two most predominant ionic species in flowback water. The paper presents a method for numerically simulating halite dissolution using the dual porosity dual permeability paradigm (DPDP) as the foundation for fluid transport in fractured reservoir.

There is increasing interest in new multi-purpose chemicals for EOR in carbonate reservoirs, because of their oil wet nature that prevents oil from being produced. A new chemical compound [Et₃NH]Cl/1.5 AlCl₃ (X = 0.6) modified with CuCl, is developed for enhancing the recovery of the free imbibition and core flooding mechanisms for naturally fractured reservoirs. Laboratory experiments have been conducted to understand the injection of such chemical into oil-wet, fractured reservoirs. The compound is tested on Iranian heavy oil sample from the Bangestan reservoir, Marun oil field. Core plugs were prepared and aged in the crude to attain restored state samples. It is found that ionic liquid compound significantly reduces oil viscosity, molecular weight and also alters wettability to a more desirable state. This chemical compound has the capability of reducing IFT and contact angle. These combined effects result in noticeable free water imbibition recovery enhancement in Amott cell after oil has undergone a reaction with the compound. The potential of the new chemical compound for increasing oil recovery and in situ upgrading of heavy oil are also examined at reservoir condition by core flooding experiments. In addition, the adsorption behavior of the new proposed chemical is also studied.

Analysis of multi-fractured horizontal well (MFHW) production data completed in low-permeability (tight) oil reservoirs has traditionally focused on long-term (online) production after the initial flowback period. Recent studies, however, have demonstrated that important information about hydraulic fractures can be ascertained from flowback data and simulation studies are now being designed to model flowback along with the online production.

In this work, a new semi-analytical model is developed specifically for modeling water and hydrocarbon production during flowback and early-time production for tight oil wells. Two flow regions are assumed: a primary hydraulic fracture (PHF) and an enhanced fracture region (EFR) adjacent to the hydraulic fracture, where reservoir permeability has been enhanced due to stimulation. Alternatively, a non-stimulated matrix region (NSR), where reservoir permeability is not enhanced due to stimulation, may be placed adjacent to the PHF. A coupled PHF-EFR model is created by assigning the average pressure in the PHF as the inner boundary condition of the EFR, and wellbore flowing pressure as the inner boundary-condition for PHF. If the initial fracture pressure is greater than reservoir pressure, the coupled model forecasts initial production to be single-phase flow of fracturing fluid, followed by two-phase flow of fracturing fluid and formation oil from the EFR to the PHF after breakthrough to the fracture. Transient flow of fluids through the PHF and EFR is modeled with the dynamic drainage area approach. Equations of coupled flow/material balance are solved iteratively at each timestep. Stress-dependent properties of fractures and matrix are handled in the solution.

The robustness of this innovative approach is tested through comparison with more rigorous numerical simulation, and its practicality demonstrated with a field example. The new technique should serve as a useful tool for petroleum engineers responsible for forecasting tight oil wells exhibiting these complexities.

We describe here a method for modifying the bulk composition (pH, salinity, hardness) of fracturing fluids and overflushes to modify wettability and increase oil recovery from tight formations. Oil wetting of tight formations is usually controlled by adhesion to illite, kerogen, or both; adhesion to carbonate minerals may also play a role when clays are minor. Oil-illite adhesion is sensitive to salinity, dissolved divalent cation content, and pH. We measure adhesion between middle Bakken formation oil and core to verify a surface complexation model of reservoir wettability. The agreement between the model and experiments suggests that wettability trends in tight formations can be quantitatively predicted and that the bulk compositions of fracturing fluid and overflush compositions might be individually tailored to increase oil recovery.

We investigate a novel hypothesis regarding the process of hydraulic fracture termination against a preexisting frictional interface. According to current understanding, crossing occurs when small tensile fractures form ahead of the crack tip, on the other side of the frictional interface, before the concentration of stress at the crack tip causes slip along the interface. Slip blunts the concentration of stress at the crack tip and causes termination. Existing crossing criteria assume that the incipient fractures ahead of the crack tip form instantaneously once the effective stress is sufficiently tensile. However, there is a poroelastic response that causes a reduction in pressure in response to opening. This is counteracted by flow into the crack from the surrounding matrix. In very low matrix permeability formations (shale, coalbed methane, etc.), flow of fluid inward from the matrix is slow, and the opening of these incipient fractures may require a non-negligible amount of time. Using the hydro-mechanical discrete fracture network simulator CFRAC, we performed a series of numerical simulations to qualitatively investigate this process. The simulations confirm that poroelastic response could affect incipient fracture initiation and hydraulic fracture crossing. Based on this mechanism, we developed a heuristic modification to an existing crossing criterion. We applied the new criterion to investigate an injection sequence for prevention of lost circulation in fractured, low matrix permeability formations. Lost circulation occurs if wellbore fluid pressure exceeds the minimum principal stress, causing fluid loss due to propagation of a hydraulic fracture. In our proposed injection sequence: (1) injection is performed at high rate to create near wellbore fracture network complexity and then (2) viscous fluid is injected into the newly formed fractures to create resistance to flow. The simulations show that this sequence may be able to mitigate lost circulation and create a stress cage around the wellbore.