Journal of Unconventional Oil and Gas Resources最新文献

Production efficiency from low permeability shale gas reservoirs requires techniques to optimize hydraulic fracture (HF) completions. This may be complicated by the presence of high horizontal in-situ stresses that result in horizontal HF, for example in parts of the Western Canadian Sedimentary Basin in northeastern British Columbia. One strategy involves the simultaneous or near simultaneous hydraulic fracturing of adjacent lateral wells to maximize the fracture network area and stimulated reservoir volume. However, changes to the in-situ stress field caused by an earlier HF on subsequent HF are not accounted for in traditional hydraulic fracturing design calculations. Presented here are the results from a set of transient, coupled hydro-mechanical simulations of a naturally fractured rock mass containing two wellbores using the discontinuum-based distinct-element method. The results demonstrate the influence of stress shadows generated by a HF on the development of subsequent HF from an adjacent well. It is shown here that these interactions have the potential to change the size and effectiveness of the HF stimulation by changing the extent of the induced fracture around the secondary well. Also, the influences of in-situ stress and operational factors on the stress shadow effect are investigated and their effects on different operational techniques are studied.

Chemical analysis of high molecular weight fractions of Nigerian bitumen was carried out to ascertain their characteristics which may assist in the development of the natural resource. Bitumen samples were fractionated by silica gel column chromatography into aromatics and nitrogen, sulphur, oxygen (NSO) compounds fractions. The fractions were analyzed for compound types using Fourier Transform Infrared (FT-IR) spectrometer. The elemental analysis of NSO compounds fraction was done using Inductively Coupled Plasma-Optical Emission Spectrometer (ICP-OES) and carbon/nitrogen analyzer. The FT-IR analysis results obtained for NSO compounds fraction showed IR peaks of the following functional groups: C–H (CH₃), C–H (CH₂), CC, C–O, CO, N–H, C–O–C, CS, C–N, SO, suggesting the presence of mixtures of paraffinic, aldehydric, anhydic, naphthenic, and heteroatoms containing compounds, while the results on aromatic fraction follow the same trend except for the absence of CS CO and C–N. The results showed higher elemental concentrations in the NSO fraction than the whole Nigerian bitumen and was confirmed by their calculated T-test values. The results also indicated that V/Ni ratio for the NSO fraction increased with the age of the producing field. Strong and positive correlations exist between most of the analyzed elements and were confirmed by the expected geochemical relationships between the sample locations as revealed by the result of cross plot analysis. The overall results indicated that refining of the bitumen may experience catalytic poisoning and its exploitation may also cause environmental degradation as well as intrinsic health hazard, considering the cumulative effect of the analyzed chemicals in ecosystems.

This paper presents a general overview of hydraulic fracturing models developed and applied to simulation of complex fractures in naturally fractured shale reservoirs. It discusses the technical challenges involved in modeling complex hydraulic fracture networks, the interaction between a hydraulic fracture and a natural fracture, and various models and modeling approaches developed to simulate hydraulic fracture–natural fracture interaction, as well as the induced large scale complex fractures during fracturing treatments.

Oil and gas-bearing shale formations have received a great deal of interest in recent years because they could make a significant contribution to global hydrocarbon production. However, their development has been hindered by the complexity of drilling and completion strategies, which must be adapted in response to shale’s mineralogy and physical properties. Matrix acidizing is commonly used as a pre-flush to the hydraulic fracturing stimulation of shale formations. The process dissolves sediments and mud solids that inhibit the permeability of the rock, enlarging the natural pores of the reservoir and stimulating flow of hydrocarbons; in some plays it is used as the main stimulation technique (e.g. Monterey shale, California). The mineralogical, mechanical, and physical responses to matrix acidizing of several important North American shale formations have been evaluated, and the effect on their recovery factors are described. Samples of Eagle Ford, Mancos, Barnett, and Marcellus shale formations were exposed to 1, 2 and 3 wt% HCl. Mass loss, compositional analysis, and X-ray diffraction based mineral assemblage characterization and quantification, show samples lost as much as 16 wt% by mass when treated with 3 wt% HCl for 3 h. The majority of the mass loss was attributed to carbonate dissolution. Analysis of post-acid treated samples show increases in porosity relative to the starting materials, but the increases in porosity are not necessarily correlated with acid strength. Images of post-acid samples demonstrate the development of cracks and fractures in Mancos, Barnett, and Marcellus samples. In contrast, the Eagle Ford samples show a homogenously distributed decrease in density, which based on mineralogical and compositional characterization, is attributed to spatially near uniform dissolution of calcite. Eagle Ford samples showed the largest increase in oil recovery factors ranging from 38% to 71% with a significant reduction in Young’s modulus ranging from 25% to 82% when exposed to HCl solutions at 93 °C.

Rapid advances in horizontal well drilling and hydraulic fracturing have made these technologies standard development strategies in unconventional gas reservoirs. Further improvements in these practices by means of numerical optimization of wellbore locations and hydraulic fracture (HF) stages spacing can enhance shale gas reserves and increase revenue from the unconventional projects. In order to solve these two challenges simultaneously as an integrated optimization problem, an automated framework for placement of horizontal wellbores and HF stages is developed and tested in this paper. Coupled with expert knowledge and engineering judgment, this workflow allows to produce unconventional assets economically.

This paper presents specifics of our novel optimization framework that improves the design and placement of HF stages in shale gas reservoirs and increases production and the net present value (NPV) of the projects by judicious application of numerical optimization algorithms. In particular, we test several gradient-based and gradient-free methods, namely, simultaneous perturbation stochastic approximation (SPSA), Genetic Algorithm (GA), and covariance matrix adaptation evolution strategy (CMA-ES). Application of these optimization strategies to a suite of test cases illustrates that it is not necessary to assume even spacing between HF stages because the algorithms have a capability to optimize HF stages spacing in homogeneous and heterogeneous geologic systems.

Horizontal drilling and multi-stage hydraulic fracturing have made the commercial development of nano-darcy shale resources a success. Low recovery factors in shale reservoirs highlight the importance of accurate modeling of fluid flow and well performance for wells draining such resources. Currently reported simulation studies assume a constant conductivity for the hydraulic fractures. However, in reality fracture conductivity varies greatly depending on the local proppant placement and concentration. An effective simulation model should also consider the presence of fracturing fluid in hydraulic fractures and matrix prior to production.

This paper presents a workflow for proper modeling of flow simulation in shale oil wells by incorporating results from the hydraulic fracturing simulator into the reservoir simulator. This approach honors the actual proppant distribution, lateral and vertical variability of the fracture conductivity, and the presence of fracturing fluid in the fractures and surrounding matrix prior to production commencement. It also gives an estimate of the recovered fracturing fluid.

It was found that ignoring the presence of fracturing fluid in the simulation model overestimated oil recovery by about 18%. Assuming elliptical and rectangular shape hydraulic fractures with constant conductivity overestimated the oil recovery factor by 27% and 35%, respectively. The conductivity of the unpropped zone affected the predicted recovery factor by as much as 50%. For the case investigated, most of fracturing fluid recovery occurred during the first year and particularly the first 2 months of production.

Pore structure of shale samples from Triassic Kockatea and Permian Carynginia formations in the Northern Perth Basin, Western Australia is characterized. Transport properties of a porous media are regulated by the topology and geometry of inter-connected pore spaces. Comparisons of three laboratory experiments are conducted on the same source of samples to assess such micro-, meso- and macro-porosity: Mercury Injection Capillary Pressure (MICP), low field Nuclear Magnetic Resonance (NMR) and nitrogen adsorption (N2). High resolution FIB/SEM image analysis is used to further support the experimental pore structure interpretations at sub-micron scale.

A dominating pore throat radius is found to be around 6 nm within a mesopore range based on MICP, with a common porosity around 3%. This relatively fast experiment offers the advantage to be reliable on well chips or cuttings up the pore throat sizes >2 nm. However, nitrogen adsorption method is capable to record pore sizes below 2 nm through the determination of the total pore volume from the quantity of vapour adsorbed at relative pressure. But the macro-porosity and part of the meso-porosity is damaged or even destroyed during the sample preparation.

BET specific surface area results usually show a narrow range of values from 5 to 10 m²/g. Inconsistency was found in the pore size classification between MICP and N2 measurements mostly due to their individual lower- and upper-end pore size resolution limits. The water filled pores disclosed from NMR T₂ relaxation time were on average 30% larger than MICP tests. Evidence of artificial cracks generated from the water interactions with clays after re-saturation experiments could explain such porosity over-estimation. The computed pore body to pore throat ratio extracted from the Timur–Coates NMR model, calibrated against gas permeability experiments, revealed that such pore geometry directly control the permeability while the porosity and pore size distribution remain similar between different shale gas formations and/or within the same formation. The combination of pore size distribution obtained from MICP, N2 and NMR seems appropriate to fully cover the range of pore size from shale gas and overcome the individual method limits.

We have measured methane and carbon dioxide adsorption isotherms at 40 °C on gas shale samples from the Barnett, Eagle Ford, Marcellus and Montney reservoirs. Carbon dioxide isotherms were included to assess its potential for preferential adsorption, with implications for its use as a fracturing fluid and/or storage in depleted shale reservoirs. To better understand how the individual mineral constituents that comprise shales contribute to adsorption, measurements were made on samples of pure carbon, illite and kaolinite as well. We were able to successfully fit all adsorption data for both gases in accordance with a Langmuir isotherm model. Our results show carbon dioxide to have approximately 2–3 times the adsorptive capacity of methane in both the pure mineral constituents and actual shale samples. In addition to obvious microstructural and compositional differences between real rocks and pure minerals, we hypothesize that water adsorption plays an important role in regulating surface area availability for other molecules to adsorb. The resultant volumetric swelling strain was also measured as a function of pressure/adsorption. We observe both clay and pure carbon to swell an amount that is approximately linearly proportional to the amount of adsorption.

This paper presents research findings on life cycle greenhouse gas (GHG) emissions associated with natural gas production in the Barnett Shale play in Texas. The data sources and approach used in this study differ significantly from previous efforts. The authors used inventories from the year 2009 tracking emissions of regulated air pollutants by the natural gas industry in the Barnett Shale play. These inventories were collected and screened by the Texas Commission on Environmental Quality (TCEQ). These data cover the characteristics and volatile organic compound (VOC) emissions of more than 16,000 individual sources in shale gas production and processing. Translating estimated emissions of VOCs into estimates of methane and carbon dioxide emissions was accomplished through the novel compilation of spatially heterogeneous gas composition analyses. Life cycle greenhouse gas emissions associated with electricity generated from Barnett Shale gas extracted in 2009 were found to be very similar to conventional natural gas and less than half those of coal-fired electricity generation.