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 (R-2 value of 0.99 for fracture length and fracture height and R-2 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. (C) 2016 Elsevier Ltd. All rights reserved.
X-ray diffraction (XRD) sample preparation methods were compared for fine grained reservoir rocks. The viability of using a hand ground, smear mount method was investigated compared to the widely used micronized, cavity mount method of sample preparation for quantitative phase analysis. Micronizing a sample before analyzing by XRD has been used successfully to reduce the average crystallite size to 10 um. However, because of the fine grained nature of shale gas reservoirs, the average crystallite size is already below 10 um. Therefore, the sample only requires disaggregation of larger particles which is easily accomplished by hand grinding. Samples were prepared using smear and cavity mount methods to compare the differences in quantitative phase abundances determined by Rietveld refinement. In addition, samples of known composition were prepared to assess the accuracy and precision of the methods. Quantitative analysis on whole rock samples shows excellent precision between the methods of sample preparation with an absolute error of 2.25 wt.% at the 95% confidence level per individual phase. Quantitative analysis on artificially prepared samples using the smear mount method shows both excellent precision and accuracy with an absolute error of 0.9 wt.% at the 95% confidence level per individual phase. A hand ground, smear mount method is therefore a quantitative and viable method for quickly assessing the mineralogy of shale gas reservoirs and fine grained rocks. (C) 2016 Elsevier Ltd. All rights reserved.
Fundamentally, recovery methods of untapped crude oils require injection of foreign material(s) in the reservoir, which subsequently promote(s) the displacement of residual oil. In chemical enhanced oil recovery (EOR), the microscopic sweep efficiency depends primarily on achievement of a low interfacial tension. The present work investigates into the surface tension and phase behavior properties of microemulsion developed from a contact between a dimeric ammonium salt surfactant achieve an ultra-low interfacial tension (IFT) was compared with a conventional polysorbate surfactant commonly used in chemical EOR. At fairly low concentration, dimeric surfactants achieved an IFT of order of 10 3 mN/m. Salinity tolerance and IFT were significantly altered not only by the heaviness i.e. API of the crude, but also by the reservoir conditions. Moreover, alkane carbon number (ACN), introduced in this work, revealed that modeling a micellar slug formulation solely based on chemical composition of the crude and/or its nature could be misleading. Presence of divalent ions was found to promote the increase in IFT rather to a shift to a lower value. Also, a relative low adsorption of micellar slug was found in both dolomite and Berea sandstone. However, active head of the dimeric surfactant showed a preferential attachment to carbonate rock while low interactions were observed for sandstone. Lastly, the present study has highlighted an inhibiting acidity activity for dimeric ammoniums salt surfactants. (C) 2016 Elsevier Ltd. All rights reserved.
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. (C) 2016 Elsevier Ltd. All rights reserved.
•A carbonate based natural gas sweetening process is simulated.•Effects of addition of certain amounts of sodium hydroxide to the solution are investigated.•The additive amount is adjusted to: 1-reach pipeline specs 2-complete removal of acid gases.•The process is simulated in different sour gas flow rates.•The needed solution flow rate and modified solution flow rate are evaluated and compared.
In this study, a Computational Fluid Dynamics (CFD) solver able to simulate shale gas flow as fluid flow in a porous medium on the macro level is presented. The shale gas flow is described by means of a tailored governing equation with both fluid properties and permeability expressed as a function of the effective pore pressure (stress effect) and with Knudsen effects included through an apparent permeability. This CFD solver, developed in the OpenFoam framework, allows for the simulation of three-dimensional fractured geometries without limitations on the shape of the domain. The solver was assessed and validated against literature data showing good agreement in terms of both recovery rate and pressure field profiles. The solver was then used to explore two different phenomena affecting shale gas dynamics: the diffusion behaviour and the influence of fracture geometry. It was shown that shale gas flow, on the macro level, is a diffusion-dominated phenomenon, and its behaviour can also be qualitatively represented by a diffusion equation. It was also shown that the early behaviour of shale gas flow is dictated by the fracture geometry, and that the reservoir dimensions have no effect on the flow at early times. Finally, a newly developed "dual-zone" solver, where the shale matrix and the fracture network are modelled as two distinct domains interacting through the common boundaries, is presented and discussed. (C) 2016 Elsevier Ltd. All rights reserved.
In recent years, petroleum assessment incorporates the petroleum system concept method instead of the play concept method to estimate petroleum resources, because conventional-unconventional petroleum resources are more reliably estimated by the genetic similarities of petroleum fluids in the petroleum system. Conventional-unconventional oil resources co-exist in the Lucaogou-Permian petroleum system in the Jimusar sag of the Junggar basin, Northwest China. The mean in-place resources (IPR) of tight oil of the Lucaogou Formation (LF) were estimated at 2.0 billion tons by an integration method in the Jimusar sag. Based on the assessment of the technically recoverable coefficient by drill productivity, it is estimated that the mean technically recoverable resources (TTR) of tight oil are about 0.11 billion tons. The mean IPR and TTR of conventional oil of the Wutonggou Formation (WF) were evaluated at 0.36 billion tons and 0.06 billion tons by analogy methods, respectively. The ratio of mean IPR of unconventional oil to conventional oil in the Jimusar is about 5: 1, but the ratio of mean TTR is only about 2:1. In addition, tight oil development is higher cost than conventional oil so far. Therefore, the development of tight oil in the Jimusar sag should be a careful consideration. Anyway, the integrated resource assessment of unconventional and conventional oil in the Jimusar sag could provide as a classic example for other lacustrine petroleum systems. (C) 2016 Elsevier Ltd. All rights reserved.
Production of unconventional oil and gas resources has played a significant role on the global energy supply, of which tight oil and gas reservoirs are drawing greater focus. The key enabler behind tight oil and gas production has been multi-stage hydraulic fracturing along extended reach horizontal wells. Despite many advances in multistage fracturing, it still remains unclear how to model the hydraulic fracturing process to provide the basis to optimize and predict the properties of fracture networks and associated enhancement of fluid production. In typical reservoir simulation practice, the conventional way to represent the hydraulic fracture is to place high permeability planes around the horizontal well - this means that the user has prescribed the orientation and length scale of the fracture before the simulation has started. In the research documented here, we explore a dynamic fracturing approach that uses a dilation-recompaction model in a reservoir simulator to model hydraulic fracturing. The key strength of the approach is that the geometry and length scale of the fracture is not prescribed a priori. The results of the simulation show that dilation-recompaction model is capable of modeling the hydraulic fracturing process prior to the flow-back and production. The oil, gas, and water rates of the model are well matched to the field data and the extent of the fractured zone predicted by the model is reasonable. (C) 2016 Elsevier Ltd. All rights reserved.
Temperature changes in and around the wellbore could lead to significant well performance and flow assurance issues. Despite its importance, near wellbore temperature change due to gas production and its importance on well performance is not well understood. Reduction of temperature in the near well bore section, could potentially lead to hydrate formation and as a result reduction of well performance.This work is aimed at evaluating the thermal behaviour in the near wellbore region of a low to tight permeability gas reservoir (ranging between 0.02 and 10 mD) during its natural depletion. The study is conducted by using a thermal-compositional simulator. The process required to simulate such thermal behaviour in a numerical simulator is outlined in this paper. This study is focused on analysing the impacts of different parameters such as reservoir and fluid properties, well trajectories and draw down magnitudes have been studied. Such parameters have an impact on JTE or conductive/convective heat transfer and therefore will affect the reservoir temperature. In addition the near wellbore temperature responses to varying production and well configurations are reviewed to identify the contributing parameter and their impact on reservoir temperature.The results of a grid sensitivity analysis showed that the choice of grid size will have a significant impact on calculated temperatures. In addition, the results reveal that significant temperature reduction could occur around the wellbore due to Joule-Thomson expansion and heat transfer in form of conduction and convention. It is also shown that size of the affected area depends on the magnitude of cooling due to Joule-Thomson expansion as well as reservoir properties such as skin and permeability. This study showed that the most influential parameter is the wellbore inflow rate due to draw down. In addition, parameters such as pressure profile along the well trajectory, inflow area along the well and reservoir quality along the wellbore will play a vital role in cooling process as well as radius of the impacted zone. The results also showed that absolute initial reservoir temperature have no significant impact on the magnitude of temperature change. Crown Copyright (C) 2016 Published by Elsevier Ltd. All rights reserved.
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. (C) 2016 Elsevier Ltd. All rights reserved.
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. (C) 2016 Elsevier Ltd. All rights reserved.
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. (C) 2016 Elsevier Ltd. All rights reserved.
Optimal development of tight-oil resources requires better petrophysical understanding of several key reservoir and mechanical properties. We highlight these for the Cardium Formation at the Pembina field, where controls on these properties appear to occur within elementary lithological components (ELCs) at the cm-to sub-cm scale moderated in part by the effects of synsedimentary bioturbation. This complexity in reservoir behavior necessitates new and innovative approaches for petrophysical property estimation, which is the subject of the current work. The workflow outlined starts with the quantification of the volumetric distribution of ELCs. For this purpose, 360 degrees photographic imaging was used to first identify ELCs, and then quantify their volumetric percentages in whole core. This initial step is limited to the exposed surfaces of the core, consequently we used X-ray computed tomography (XRCT) in order to project the ELCs volumetric distribution into the core interior. The correlation between CT number, mineralogy, and bulk density of the rock further allowed porosity to be calculated from XRCT and shed light on its distribution throughout the core interior. Variations in fine-scale permeability were evaluated by collecting pressure-decay profile permeability measurements across a core slab surface following a 5 x 5 mm-2D grid. Relationships between ELCs permeability and porosity were then generated and, when combined with the volumetric distribution of ELCs previously assessed, enabled a 3D distribution of reservoir quality at the mm-scale throughout the core. Finally, microhardness data was collected on the same 2D grid enabling ELC-scale quantification of mechanical properties. Reservoir properties of whole core samples identified in previous publications appear to be reasonably predicted when utilizing ELCs-specific permeability versus porosity transforms and volumetric percentages generated in this study, thus demonstrating scale-up potential. (C) 2016 Elsevier Ltd. All rights reserved.
Flowback water is usually highly saline and the salt concentration varies by time and well location. Understanding the origin of the flowback salts is essential for evaluating fracturing and flowback processes. In this study, laboratory and field analyses are performed to investigate the origin of the flowback salts. The field data includes the total salt concentration (salinity), individual ion concentration, pH, and dissolved oxygen measured during the flowback process for three wells completed in the Horn River Basin. The rock mineralogy is determined using XRD. The cation exchange capacity (CEC) of shale samples are measured using ammonium acetate method. Water and oil imbibition experiments are conducted for shale samples of different surface-to-volume ratio. The individual ion concentration is measured during the water imbibition experiments using ICP-MS and IC. EDXS analysis is used to investigate the surface of natural fractures.Noticeable amount of barium found on the surface of natural fractures suggests that the barium in the flowback water primarily originates from the natural fractures. Furthermore, the samples with higher clay content have higher CEC. During the water imbibition process, these samples have higher and faster ion transfer from shale -to -water; suggesting the mobilization of the exchangeable ions from the clays. During the water imbibition experiment, the Na/CI and K/CI ratios are initially high and decrease at the later times. Leaching of the exchangeable sodium and potassium ions from the clay minerals is a possible reason for the initial high Na/CI and K/CI molar ratios. The dissolution of chloride -bearing components increases the chloride concentration, which decreases the Na/CI and K/CI molar ratios at later times. The measured pH is slightly above 8 for all of the flowback water samples. The presence of natural buffer systems such as calcite and dolomite may explain the neutral pH range of the flowback water. (C) 2016 Elsevier Ltd. All rights reserved.
The mesostructures of aqueous solutions (one simple type of water-based drilling fluids), with a kinetic hydrate inhibitor (polyvinyl pyrrolidone, PVP) or/and drilling fluid additive (sodium carboxymethyl cellulose, CMC), and their rheological properties after two shearing actions (600 r/min and 6000 r/min) were respectively investigated using a scanning electronic microscope (SEM) and a six -speed rotation viscometer, considering the different shearing actions imposed on drilling fluids during their circulation in the well. The results show (1) aqueous solutions with polymers (CMC, PVP and CMC + PVP) exhibit three different types of network framework (normally in the size of several to tens of micrometers), thin films + thin rods, globular particles + thin rods, and thin films + thin slices. Upon increasing the concentration of CMC or/and PVP, the thickness of the backbones and branches of the network framework increased, causing the volume of the pore space to decrease and the apparent viscosity and shear stress to increase. The tackifying effect of CMC was stronger than that of PVP, and the synergistic effect of CMC and PVP apparently increased the apparent viscosity and the shear stress. (2) With the shear rate increasing from 600 r/min to 6000 r/min, the apparent viscosities and shear stresses of these aqueous solutions decreased to some degree, and the four aqueous solutions of 0.75 wt% CMC, 1.5 wt% PVP, 0.75 wt% CMC + 1 wt% PVP, and 0.75 wt% CMC + 1.5 wt% PVP had relatively larger decreases in the apparent viscosity and the shear stress, which might result from changes in the spatial morphology of the network framework and the pore space, the spatial distribution and contents of the three different states of water, and the mobility of free water. The changes in the mesostructures might affect the local conditions of the heat and mass transfer in hydrate dissociation and formation in the annular space. (C) 2016 Elsevier Ltd. All rights reserved.
The deflection of initial fractures and the formation of new fractures as non-planar fractures were investigated, which both are possible mechanisms for production improvement in refracturing or SRV (Stimulated reservoir volume). Firstly, initial fractures were formed under initial tri-axial stresses loading. Secondly, the formation and development of new fractures from refracturing were stimulated with changing horizontal stresses. The results show that (1) During refracturing new fractures were formed, and the initial fractures were re-opened, initiated and deflected. Whlie most of the deflection was identified as tensile and shear failure. (2) New fractures do not always result from the stress field change. This implied the smaller horizontal stress difference was, the easier the initial fractures were deflected, and the larger horizontal stress difference was, the easier the new single-wing fractures were formed on the walls of the initial fractures; (3) Deflection of initial fractures was more easier than formation of new fractures. The study indicated that, the injection pressure of deflection was lower than the initial breakdown pressure, while the formation of new fractures required higher pressure than initial breakdown pressure. (4) The injection rate contributed to a significant effect on the formation of new fractures. When injection rate was low, the formation of new fractures on the walls of the initial fractures was difficult. But when injection rate was high, new single-wing fractures formation was easily occurred on the walls of the initial fractures. (C) 2016 Elsevier Ltd. All rights reserved.
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. (C) 2016 Published by Elsevier Ltd.
The gradual depletion of the conventional energy reserves and ever growing energy demand has been the matter of global concern over the last few decades. Shrinking coal and petroleum resources have posed researchers to look for exploration and exploitation of unconventional gas resources. In this scenario, natural gas is not only a promising alternative solution towards mitigation of energy crisis but also a potential candidate to reduce the environmental impact through restraining the greenhouse gas effect. In this context, methane extraction from coalbeds has gained its commercial viability in different parts of the world viz. USA, China, Australia, India etc.The review highlights global scenario of coalbed methane (CBM), transport of methane through coalbed, the sorption behavior of methane within the unconventional gas reservoirs, thermodynamic activities of gas adsorption into reservoir bed in terms of thermodynamics parameters viz. Gibbs free energy, temperature, enthalpy and entropy and the kinetic study of the contrivance of methane discharge for indicating the type of gas adsorbed onto the surface of coal matrix and time lapsed for saturation of coalbed. Maturity, geology and geochemical characteristics of coal have been reviewed for differential methane sorption in coal reservoirs. Diffusion and sorption isotherm model which fits the experimental data related to gas retention and release mechanism has also been discussed. Finally, different physicochemical characteristics of coal responsible for the methane gas storage and recovery have been discussed. (C) 2016 Elsevier Ltd. All rights reserved.
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.
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. Published by Elsevier Ltd.
