查看更多>>摘要：Natural gas flow in shale pore systems determines the accumulation and production of shale gas. Under the conditions of reservoir, gas flow in such shale pores is significantly different from that in conventional reservoirs. Studies of gas flow under such conditions are usually limited to simple pore models with tube/slit geometries or bundle of tubes/slits, which constructs important theoretical basis, however, cannot represent the pore networks of shales. For directly simulating gas flow in complex media, we proposed a modified microscale lattice Boltzmann (MM-LB) model, in which the local effective mean free path (MFP) at any location of the pore system with complex geometry corrected by a custom two-dimensional (2D) eight-direction wall function was considered to capture the effective relaxation time for each lattice node in LB model. What's more, to consider slip velocity at solid boundaries, a combined bounce-back specular-reflection (BSR) scheme was adopted. The MM-LB model was firstly validated in 2D pore systems with simple slit/channel geometries and complex geometries (square and triangular cylinder flows) and in a 3D Sierpinski carpet, where good agreements with linearized Boltzmann solutions, molecular dynamics (MD) simulation and the direct simulation BGK (DSBGK) method results were found. Using the MM-LB model, we quantified the end effect on gas flow through pore throat and found that the end effect is caused by not only the streaming bending but also the variance of MFP (i.e., viscosity) throughout the pore throat. Finally, we applied this model to simulate shale gas flow in three digital reconstructions of kerogen pore systems and compared the results of apparent permeability prediction with Klinkenberg model and Beskok-Karniadakis (B-K) model. It is showed that the apparent permeability of gas flow in shales decreases with the decrease of temperature or the increase of pressure, and the pressure has a greater effect than temperature. For similar pore structures, the apparent permeability increases with the width of pore body and pore throat, especially the pore throat, which dominates the overall flow velocity of the entire flow field. According to the comparison and analysis of the results of MM-LB model with Klinkenberg and B-K model, it can be inferred that permeability prediction based on models of tube/slit (or bundle of tube/slit) pores misestimate the apparent permeability due to ignoring the connectivity and the end effect, especially for the conditions of lower pressures and nanoscale pore spaces.
查看更多>>摘要：With the widely use of hydraulic fracturing technique, large volumes of fracturing fluids are injected into shale reservoirs. The physical and chemical reactions between fracturing fluids and shale will change the surface roughness of shale fractures, which further impacts the production efficiency of hydrocarbons. To quantify the impacts of fracturing fluids on shale fracture roughness, a series of imbibition tests were conducted on shale samples soaked in different fracturing fluids (acid (pH = 6), neutral (pH = 7) and alkaline (pH = 8)) with different time (short-term (0-3 months) and long-term (3-12 months)). The surface morphology, microstructure, mineral composition, and element changes of shale samples before and after imbibition were determined. The results showed that: (1) pyrite and kaolinite were the main minerals that dissolved in the short-term of imbibition. The dissolution of pyrite caused the rapid decreasing of pH values for all fracturing fluids (decreased by 43%-51%). In the long-term of imbibition, clay minerals (illite-montmorillonite) and feldspar were the major dissolved minerals, resulting in the rise of pH values (increased by 10%-19%). (2) the dissolution, hydrolysis, and hydration process during imbibition resulted in the increase of fractal dimension (increased by 9%-30%). Alkaline fracturing fluid had higher effect on the roughness of shale than that of acid and neutral fracturing fluids. (3) the joint homogeneity on the shale fracture surface which obtained from the joint rose diagram revealed that acidic and neutral fracturing fluids enhanced the joint homogeneity (increased by 64% and 74.6%), whereas alkaline fracturing fluid weakened the joint homogeneity, which decreased by 43.8%. In this study, the impact of fluid-rock interaction on shale fracture surface roughness is explored for the first time, a variety of methods are used to evaluate, and the differences of different methods are compared. The results show that different pH fracturing fluids have significant changes in the surface roughness of shale fractures. For shale formation with high pyrite content, alkaline fracturing fluid has stronger reconstruction ability. Above conclusions may have significant impact on the efficiency of hydraulic fracturing.
查看更多>>摘要：One of the problems plaguing many Oil and Gas operators is the formation of stable emulsions in their separation systems. Emulsions are highly specific colloidal mixtures of two immiscible fluids, such as water and oil, in the presence of some stabilizing agent. The aim of this work is to assess and predict the stability of emulsions observed in the North Coast Marine Acreage (NCMA) of Trinidad and Tobago. The specific objectives are to (1) Determine the stabilizing factors of emulsions observed in NCMA via laboratory work, (2) Establish a model for predicting emulsion stability expected of a surfactant stabilized Pickering emulsion system and (3) Compare the results of laboratory testing to model results using NCMA emulsion samples. Two types of emulsions were found in the NCMA samples: (1) a cloudy white emulsion and (2) a thick grey rag emulsion. A series of laboratory testing was conducted to determine the stabilizing factors. Two Machine Learning algorithms were attempted, k Nearest Neighbor and Random Forest Classification, to predict the emulsion result. The Machine Learning models developed were able to predict an outcome of emulsion stability proving the concept that these algorithms can be used for practical assessment. However, the accuracy compared to the laboratory findings was significantly lower than expected at only 45%. This proves that the behaviour of the NCMA emulsion system is unique with few universally applicable trends and warrants further detailed assessment.
查看更多>>摘要：Mixed siliciclastic-carbonate reservoirs are considered as new important high-quality exploration targets because giant hydrocarbon accumulations have continually been discovered in these reservoirs in continental rift basins. This study used a combination of reservoir geological and geochemical evidence to investigate the characteristics and formation mechanisms of mixed siliciclastic-carbonate reservoirs in the first and second members of the Shahejie Formation in the Bozhong Sag, Bohai Bay Basin, China. The results show that bioclastic-dominated mixed rocks represent high-quality reservoirs because they did not only preserve a amount number of primary pores but also preserved a fair proportion of secondary pores that contain organic matter fabrics or associated secondary pores. The main diagenetic processes recognized in the mixed sediment reservoirs are micritization, cementation, dissolution and compaction. Micritization in the contemporaneous stage, dolomitization in the penecontemporaneous stage and leaching of meteoric freshwater in the early diagenetic process are the main controlling factors leading to the formation of high-quality reservoirs. The micritic envelope effectively resists compaction, preserving a high amount of primary porosity, and the early leaching of meteoric freshwater can produce a large amount of secondary dissolution pores. This study does not only reveal the genetic mechanism of high-quality reservoirs of mixed rocks in continental basins but also provide significant guides that can be utilized to search and produce from new types of high-quality reservoirs.
查看更多>>摘要：In order to solve the problem of conventional preformed particle gel (PPG) with relatively high cost and poor strength and shearing resistance, a preformed sawdust gel particle (S-PPG) with a more superior performance than PPG was presented. A series of S-PPG with different mass ratio of sawdust particles to gelling liquid were prepared with free radical polymerization. It makes acrylic acid and acrylamide as polymerization monomers, N, N '-methylene bisacrylamide as crosslinking agent, ammonium persulfate as initiator and sawdust particles as enhancer. In general, enhancer content was less than 1%, but the content of enhancer in this work was increased by about 20-30%. The microscopic morphology, swelling property, viscoelasticity, yield stress, creep-recovery characteristics and shearing resistance of S-PPG in the formation water had been studied. The plugging behavior of S-PPG was studied using core flooding test. The results indicated that the swelling ratio of S-PPG (1:5) in the formation water was 8. S-PPG showed better viscoelasticity properties, shearing resistance and higher yield stresses than PPG. Moreover, the plugging rate of the plugging system with 3000 mg/L S-PPG (1:5) improved from 85.1% to 90.5% in fracture core compared with PPG. S-PPG (1:3) improved the plugging rate from 85.1% to 91.9%. The research results provide an alternative plugging material in fractured reservoirs.
查看更多>>摘要：Determining the potential of reservoirs and production zones is very important to reach maximum product performance and decrease hydrocarbon recovery costs. The calculation of the Water Saturation (S-W) significantly affects oil-in-place estimations. The Saturation-Height Function (SHF) is operated to predict the saturation in the reservoir for a given height above the free water level. Typical approaches for predicting water saturation as a function of rock properties and height above contact include two types, those based on capillary pressure curve averaging and log-based techniques. The goal of this study is to define an appropriate SHF and S-W using the usual functions to delineate production zones using rock typing with an example from the Dorood oilfield in the Persian Gulf. In this study first, the reservoir has been divided into different rock types and water saturation is estimated by different methods in each rock type. The Reservoir Quality Index (RQI) along with Water Saturation profile for representative rock types were used for determining reservoir zones. Accordingly, a formulation was developed to model the behavior of Capillary Pressure (P-C) as a characteristic of S-W and to determine the Free Water Level (FWL) based on laboratory data. To achieve this goal, the appropriate saturation-height functions and their coefficients were chosen for representative reservoir rock types. The Pc curves are classified based on Discrete Rock Types (DRT) and a proper saturation-height function was assigned for individual rock types. Finally, some of the most common equations for calculating SHF were fitted to the representative Pc curve of each rock type and coefficients of the equation for any rock type were determined by using the MATLAB software in the studied carbonate reservoir. After investigating the results of fitting different SHF, water saturation was calculated using a modified lambda function and compared with the log-derived water saturation. The SHF applied, could be used to estimate saturations of unreachable zones of the field.
Kassem, Ahmed A.Osman, Osama A.Nabawy, Bassem S.Baghdady, Ashraf R....
25页
查看更多>>摘要：The channelized carbonate reservoirs played important role in the global hydrocarbon production. This study presents a new contribution to the carbonate platform system of the Turonian sediments in the Gulf of Suez. The siliciclastic fluvial channelized system incised the carbonate platform in October Field to deposit excellent reservoir unit. Also, the study interprets the facies change, depositional environment, and petrophysical characteristics of the Turonian Wata sequence, to figure out the fluvial channel reservoir distribution and discrimination using surface outcrops in addition to five cored wells. The petrographic analysis and depositional settings interpretations were conducted to the subsurface and outcrop samples. Then, the conventional core analysis measurements were combined with borehole logs for optimum reservoir discrimination, rock typing, and flow units interpretation. Besides, we studied the reservoir heterogeneity and predict permeability and reservoir rock typing in the un-cored intervals. Our finding revealed that the Wata Formation is subdivided into three main lithological units characterized by 16 microfacies. The lower and upper ones are carbonate dominated, composed of wackestones, packstones, and grainstones which is deposited in platform setting belong to lower/middle shelf and mid/outer shelf to outer ramp setting respectively. The middle unit is classified into lower and upper zones, where the lower clastic zone is composed of vari-sized sandstones, siltstone, and mudstone with some plant remains deposited in a point bar of fluvial channel and flood plains. The upper zone is composed of clastic/ carbonate intercalations deposited in intertidal/shelf settings. The integration between the petrography and petrophysics enables discriminating the Wata sandstone reservoir into four static rock types (PSRT 1-4), which are controlling its reservoir quality and heterogeneity. The PSRT1 and PSRT2 have the best reservoir quality in the channelized unit and are recommended to be tracked along with October Field. The HFU2 and HFU3 are the main flow capacity in the Wata reservoir, composed of PSRT1 and PSRT2, and represented by the calcareous and ferruginous quartz arenite microfacies. This study presented a secondary dolomitized microfacies with 85% oil potentiality resulted from the incision of the fluvial channel above the aerially exposed carbonate lower unit. The research addressed the optimized petrophysical properties and reservoir heterogeneity of the channelized Wata sequences. In addition, it highlights a guidelines for further exploration and production of these reservoirs in the basin.
查看更多>>摘要：Data-driven deep learning algorithms have shown good performance in the field of petroleum industry. However, some research has begun to be keen to incorporate physical laws into machine learning algorithms, so as to establish a "data + physical laws " dual-drive model, which can more effectively guide deep learning. In this study, reservoir geology, hydraulic fracturing, and dynamic production data were considered to establish a fracturing effect evaluation model for coalbed methane reservoirs. The combined network is designed to fully excavate the characteristics of dynamic and static data and solve the problem that the network ignores static data due to excessive dimensions of dynamic data. Furthermore, a neural network considering physical constraints was developed to better evaluate the fracturing effect by incorporating the initial conditions and expert experiences into the loss function. The deep learning-based fracturing effect evaluation model not only fits data driven methods including reservoir geology, hydraulic fracturing and dynamic production data, but also adheres to the guidance of physical constraints. The experimental results show that compared with the conventional machine learning methods, the fracturing effect evaluation model has better performance on the prediction of crack half-length and permeability after fracturing due to combined network and physical constraints, with the overall RMSE of 6.11 m and 0.533mD respectively. In addition, through the analysis of influencing factors, it can be obtained that reservoir geology and hydraulic fracturing parameters can contribute more than 90% to the prediction of fracture half-length. Moreover, reservoir geology, hydraulic fracturing and dynamic data all play an important role in the permeability after fracturing, among which dynamic data has the highest contribution rate, with more than 40%.
查看更多>>摘要：Understanding pore heterogeneity is essential to obtain insights into the gas storage, transport, and recovery from coal. The pore structure in analytical sample particles of different sizes varies significantly, leading to inaccurate pore characterization. In this study, we discuss the effect of particle size on the pore structures and multifractal characteristics of two samples with six particle sizes using low-pressure gas adsorption. The results show that, with decreasing particle size, the mesopore and macropore volumes and specific surface areas (SSAs) of the two samples fluctuate. The variations of micropores that contribute to most of the total pore volume and SSA (>90%) are different. Multifractal analysis shows that the subsamples with the smallest particle size have the most homogeneous pore structures and the highest pore connectivity. We reveal a negative power function relationship among particle size and pore volume, and SSA, indicating that crushing opens up more pores that were initially closed. The differences between the two coal samples may be caused by the combined effects of crushing and associated impacts (e.g., pore collapse), coalification, incomplete equilibration of N2 adsorption, and mineralogical inhomogeneity. Our results demonstrate that in the range of test particles, the finer the particle size used, the more accurate the evaluation of highly mature coal adsorption properties.
查看更多>>摘要：Estimating undeveloped reserves in unconventional reservoirs has important practical and legal implications. Unconventional reservoirs lend themselves to the use of statistical workflows which often first determine a distribution of well EURs and then treat the EURs at the undeveloped locations as regionalized variables. This approach was formalized by the Society of Evaluation Engineers in Monograph 3 published in 2010 which presents a workflow to assess proved undeveloped reserves in unconventional assets based on the statistical bootstrap approach. However, the recommended workflow makes the strong assumption of spatial independence amongst well pairs which significantly limits the application of the workflow as this assumption is often violated in practice. Further, applying this workflow to reservoirs that violate the independence assumption can result in the underestimation of uncertainty and thus overconfident estimates. To overcome this limitation, we introduce a geostatistical workflow that honors the spatial context of the data by bootstrap sampling with the effective number of independent data, n-effective, rather than the total number of data, thus generating uncertainty estimates that honor the spatial context of the data and extend the applicability of the workflow to fields with spatially correlated data.
NSTL
Elsevier