Identification and research of factors affecting the optimal distribution of well flow rates in space

The paper discusses and research the factors affecting the filtration rate to reduce stagnant zones in the domain and spreading outside the block under consideration. The main hydrodynamic factors in production by In-Situ Leaching are the distribution of permeability in the reservoir and well flow rates. The study of the factors was carried out on the basis of mathematical models using Darcy Law and Law of Conservation of Mass. Calculation was accomplished on a two-dimensional area with an isotropic and non-uniform permeability distribution to determine the effect of permeability on the leached area. The permeability coefficient was distributed respectively over three zones, in the southern part the permeability was low, in the central transition from low to high, respectively, in the northern part there was a highly permeable zone. Three wells were located in the domain, with the production well in the center of the domain. Injection wells are located symmetrically with respect to a horizontal line passing through the center of the area under consideration. The calculation was carried out for three modes of well flow rates with the ratio of the flow rates of the injection wells 0.5 / 0.5, 0.2 / 0.8, 0.8 / 0.2 relative to the flow rate of the production well. On the basis of comparative analyzes of the obtained results, it is concluded that: at the same flow rates, regardless of the permeability of the zones, the results obtained show that the leaching area in the low-permeability zone is larger in comparison with the high-permeability zone; with an increase in permeability, the shape of the leaching zone tends from round to drop-shaped; with an increase in the flow rate of wells in the radius of the leaching zone, it increases if the flow rate of solutions is much higher than the filtration rate.

Study of the Influence of Change in the Sandstone and Aleurolite Collector Properties on the Geological Modeling Quality

The initial data when creating both geological and hydrodynamic reservoir models can lead to errors in the modeling results and the subsequent distortion of the economic assessment and prospects of an oil or gas field. In order to improve the predictive reliability of reservoir hydrodynamic models, a core material study for the Tula object of four fields at the Babkinskaya anticline was carried out. The ratio analysis of porosity (Kp), rock density () and permeability (Kperm) for sandstones and aleurolites was carried out. Using a statistical core sampling based on porosity, density and permeability parameters, a separation by sedimentation processes was carried out for all considered lithological differences. For aleurolite and sandstone, we could talk about the differentiation of characteristics in the process of reservoir properties formation. The values of the parameters Kp, and Kperm, determined from laboratory core studies, were combined into a single statistical sample for the possibility of developing a methodology that would be aimed at describing Kperm using the integrated laboratory studies, namely by adding rock to the analysis. As a result of statistical analysis, it was found that permeability in intervals with low reservoir properties was controlled with the same significance degree by both porosity and rock density for all lithological differences. At the same time, the presence of highly permeable reservoirs for sandstones and their practically absence for aleurolites were noted. For all lithological differences, relationships were established between the permeability coefficient not only with porosity, but also with rock density. The methodology for constructing statistical models for calculating permeability from the values of porosity and rock density was implemented separately for the fields of the eastern and western parts of the Babkinskaya anticline. The described approach to taking into account the influence of rock density on permeability made it possible to determine the differentiated influence of lithotypes on the filtration characteristics of the reservoir. When modeling a reservoir, it is necessary to move from linearity to nonlinearity and take into account that the problem of permeability distribution in the reservoir being solved is somewhat more complicated: in different areas, sometimes the permeability is not controlled by porosity in principle, but somewhere only this parameter prevails. The methodical approach was recommended for 3D modeling. Revealing the relationships between the parameters was most important when developing a methodology for tuning the model in the interwell space. The development of a reliable estimate of permeability for the vast majority of wells will significantly improve the efficiency of hydrodynamic modeling. At the same time, it is necessary to comprehensively take into account the identified relationships between the petrophysical characteristics of production layers. The use of the approach to the analysis of petrophysical characteristics will allow obtaining a more reliable and less subjective hydrodynamic model of the formation.

Identification and Characterization of High Permeability Zones Using Conventional Logging and Production Logging Data: A Case Study of Kela 2 Gas Field

High permeability zones in the water-drive gas reservoir tend to act as dominant channels for formation water to invade into gas reservoir from the aquifer. The presence of high permeability zones results in uneven water flow front in reservoir and early water breakthrough in gas well, which seriously affects the gas field development. In this paper, conventional logging and production logging data are used to identify and characterize high permeability zones, so as to guide the optimization of development plan of Kela 2 gas field. A method to determine the lower limit of high permeability zones by using cumulative frequency curve of permeability distribution is proposed, and high permeability zones of 21 wells are identified. These high permeability zones account for 10–15% of the effective reservoir thickness in single wells, and they are mainly distributed in the middle of the Bashijiqike (K1bs) Formation (i.e., K1bs12, K1bs21 and K1bs22). The analysis of production logging data shows that the effective gas producing intervals only account for 29.2% of the total number of test intervals, most of which are related to high permeability zones. Further study shows that the high gas flow from the high permeability zones dominates the wellbore production profile, and the gas in low permeability zones flows vertically to the high permeability zones and horizontally to wellbore through these zones. Through the analysis of production profiles over the years and computer modelling, it is confirmed that water channelling occurred in some gas wells at the depth where the high permeability zones are located, which leads to a significant decline in production of these wells. Based on the study of distribution and behaviour characteristics of the high permeability zones, two suggestions on controlling inhomogeneous water invasion are put forward to realize the sustainable and stable production of the gas field.

Darcy model with optimized permeability distribution (DMOPD) approach for simulating two-phase flow in karst reservoirs

Darcy model fails to accurately model flow in karst reservoirs because the flow profiles in free-flow regions such as vugs, fractures and caves do not conform to Darcy’s law. Flows in karsts are often modelled using the Brinkman model. Recently, the DMOPD approach was introduced to reduce the complexity of modelling single-phase flow in Karst aquifers. Modelling two-phase flow using the Brinkman’s equation requires either a method of tracking the front or introducing the saturation component in the Brinkman’s equation. Both of these methods introduce further complexity to an already complex problem. We propose an alternative approach called the two-phase Darcy’s Model with optimized permeability distribution (TP-DMOPD) to model pressure and saturation distributions in karst reservoirs. The method is a modification to the DMOPD approach. Under the TP-DMOPD model, the caves are initially divided into zones and the permeability of each zone is estimated. During this stage of the TP-DMOPD model, the fluid inside the reservoir is assumed to be in a single-phase. Once the permeability distribution is obtained, the two-phase Darcy model is used to simulate flow in the reservoir. The example applications tested showed that the TP-DMOPD approach was able to model two-phase flow in karst reservoirs.

Study on Mechanical Behavior and Seepage Characteristics of Coal Mass during Unloading

With the increase of buried depth, the content of gas increases gradually. The gas in the mining process will lead to gas gush and other dynamic disasters, or even coal and gas gushing in front of the working face. Therefore, the study on the permeability distribution of coal and the surrounding rock is the core work of coal and gas mining at the same time. To study the mechanical behaviors and seepage characteristics of coal mass during unloading is to prepare for coal and gas mining in the future, which can not only ensure the safety of operators to the maximum extent but also increase the mining rate as much as possible. Based on the stress-strain curve and seepage curve, the brittleness index and seepage characteristics of coal are analyzed. The greater the brittleness index is, the more likely the coal mass is to produce cracks, and then to form large cracks, or even fracture. Through the study of brittleness index and seepage characteristics of coal mass, the mechanical behavior of coal mass can be easily obtained, so as to guide the mining of coal mass.

Selecting a Method for the Manufacture of Porous Powder Filter Products

The article considers three methods of increasing the distribution uniformity of properties over the filtration area of powder filter materials at different stages of their manufacturing. It is shown that granulation of metal powders with a pore former increases the uniformity of permeability distribution over the filtration area by a factor of 2.3–3.5. Dry radial isostatic pressing ensures high distribution uniformity of properties, while the coefficient of variation of local permeability does not exceed 0.17. Radial compression allows increasing the uniformity of permeability distribution over the filtration area by 15 ... 22 % compared to that for the original powder filter materials. The selection of the method used in practice is determined by the shape, size and properties of the manufactured products and initial powders. The considered methods can be used in petrochemical engineering for the manufacture of porous powder products for filtering purposes, used to trap catalyst particles, filters for fine and coarse fuel and oil purification.

Influence of permeability on the hydrothermal system at Vulcano Island (Italy): inferences from numerical simulations

Volcano-hydrothermal systems are governed by complex interactions between fluid transport, and geochemical and mechanical processes. Evidence of this close interplay has been testified by distinct spatial and temporal correlations in geochemical and geophysical observations at Vulcano Island (Italy). To understand the interaction between fluid circulation and the geochemical and geophysical manifestations, we perform a parametric study to explore different scenarios by implementing a hydro-geophysical model based on the equations for heat and mass transfer in a porous medium and thermo-poroelastic theory. Numerical simulations allow us to define the controlling role of permeability distribution on the different modeled parameters as well as on the geophysical observables. Changes in the permeability within the highly fractured crater area could be responsible for the fluctuations in gas emission and temperature recorded during the crisis periods, which are accompanied by shallow volcano-seismicity in the absence of significant deformation and gravity variations. Despite the general medium permeability of the volcanic edifice, the presence of more highly permeable pathways, which allow the gas to rapidly escape, as testified by the presence of a well-developed fumarolic field, prevents the pressure buildup at shallow depths. Graphic abstract

Stratigraphic and structural control over permeability distribution in poorly consolidated siliciclastic rocks

Permeability models are very relevant for the characterization of oil systems. However, limitations related to the resolution of seismic data make it difficult to identify subseismic, sedimentary, and tectonic structures, which can significantly impact the flow pattern. This study analyzed the spatial variability of permeability according to stratigraphic and structural geology control to propose a useful model for poorly consolidated, fractured, and faulted siliciclastic reservoirs. In an outcrop analogue to this type of reservoir, air permeability was measured in 3 orthogonal directions at 24 points, spaced 2 m apart.The models were obtained by sequential Gaussian simulation (SGS) after statistical data treatment. The models were validated to ensure the consistency of the generated scenarios. Permeability values showed a positive asymmetric distribution and reduced medians toward tectonic structures. The fitted semivariogram model was exponential, with higher spatial continuity in the horizontal flow direction and lower in the vertical one. The permeability models emphasized the importance of considering subseismic structures in the flow analysis of reservoirs since they have proven to play a significant role in the permeability distribution in the outcrop assessed.

Production Logging, Openhole-Log Interpretation Help Discover New Oil Reserves

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30644, “Discovery of New Oil Reserves by Combining Production Logging With Openhole-Log Interpretation in Low-Resistivity Pay,” by Xinlei Shi, Peichun Wang, and Jinxiu Xu, CNOOC, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. In this paper, the authors examine the evaluation of a low-resistivity-pay siliciclastic reservoir in Bohai Bay, China. A significant amount of irreducible water is bound to the rock surface, dramatically lowering the resistivity of the pay zone. The authors explore a theory that the low resistivity is caused by bound water trapped in clay minerals, using production logging to provide the ground truth of reservoir fluids in the low-resistivity pay and improve the petrophysics model. With the improved model, production predictions were made for offset wells based on their openhole logs. The production histories of these wells are highly consistent with the authors’ predictions. Introduction LD oil field is in the eastern Bohai Sea, China, structurally in the transition zone between the Liaohe depression of the Tanlu fault and the Bozhong depression and at the dip end of the Bodong low uplift extending to the northeast. The main oil reservoirs are developed in the Guantao and Dongying formations. Reservoir depth ranges from approximately 1022.1 to 2585.8 m. Reservoir lithology is mainly sandstone and gravelly sandstone. The porosity distribution range of the Guantao formation is 24 to 30%. Permeability distribution range is 333 to 3333 md belonging to medium-high-porosity and - permeability reservoirs. The porosity distribution range of the Dongying formation is from 6 to 12%, and the permeability distribution range is from 3 to 33 md belonging to medium-low- porosity and -permeability reservoirs.