Multiphase Numerical Simulation of Air Sparging Performance

Physical investigation of acoustic waves induced by the oscillation and collapse of the single bubble

A wind tunnel study of the airflow field and shelter efficiency of mixed windbreaks

The paper focuses on the filtration and electrical anisotropy coefficients and relationship between vertical and horizontal permeability in sandstone reservoir rocks. Field case study of DDB reservoir rocks. Petrophysical properties and parameters are estimated from core and log data from a Moscovian and Serpukhovian stages of Dnipro-Donetsk Basin (West-Shebelynka area well 701-Bis and South-Kolomak area well 31). Routine core analysis included estimation of absolute permeability, open porosity, irreducible water saturation and electrical resistivity (on dry and saturated by mineralized solution) of 40 core samples along two orthogonal directions. Shale fraction is estimated using well logging data in wells which are analyzed. The authors report that reservoir rocks are represented by compacted poor-porous (φ <10 %), low permeable (k<1mD) laminated sandstone with different ratios of clay minerals (Vsh from 0,03 to 0,7) and high volume of micaceous minerals (in some cases 20-30 %). Research theory. One of the main objectives of the work is to develop empirical correlation between vertical permeability and other capacitive and filtration properties for compacted sandstone reservoirs. A modified Kozeny-Carman equation and the concept of hydraulic average radius form the basis for the technique. Results. Coefficients of the anisotropy of gas permeability (IA) and electrical resistivity (λ) are defined based on the results of petrophysical studies. The experiments proved that IA lies in a range from 0,49 to 5 and λ from 0,77 to 1,06. Permeability and electrical resistivity anisotropy in most cases have horizontal distribution. It has been shown that in West-Shebelynka area sample №1 (depth 4933 m) there is probably no fluids flow in vertical direction and in samples №№3 and 15 fractures have the vertical orientation. We have also found that the values of electrical and filtration anisotropy for all samples of South-Kolomak area are similar, this characterized the unidirectionality in their filtration properties, as well as the fact that the motion of the fluid flow mainly in the horizontal direction. In the studied rocks the degree of anisotropy has been concluded to depend on the volume of clay and micaceous minerals, their stratification, fractures, density, and their orientation. New correlation between vertical permeability, horizontal permeability and effective porosity are developed for Late Carboniferous DDB intervals that are analyzed.

The presence of impermeable horizontal barriers (such as shales) in a reservoir is known to have a significant effect on its vertical permeability. Since calculation of an effective vertical permeability of such a reservoir is important, approximation of the distribution of vertical permeability may also be useful for analysis of the two-phase vertical flow of buoyant fluid, such as may occur in the subsurface injection of carbon dioxide into saline formations. In this situation, the maximum likely vertical permeability of a reservoir with impermeable barriers, which could be estimated from the probability distribution of the vertical permeability, is a more useful metric than an overall effective value for the vertical permeability due to its presumed relationship to breakthrough time. In this article, we derive expressions for the mean and variance of the vertical permeability of both two and three-dimensional reservoirs using the statistical streamline method of Begg and King (Paper No. 13529, 1985), and calculate the probability distribution of the vertical permeability of a reservoir with impermeable barriers. In addition, we also provide a simple statistical analysis of the presence of high vertical permeability regions in the reservoir, which may be of importance in coarse-scale simulations of vertical migration.

For an oil reservoir subjected to waterflooding, the horizontal and the vertical permeabilities have a considerable influence on the areal and vertical sweep efficiencies. Particularly, in the case of the Natih formation – a multilayered and heterogeneous reservoir located in Oman – a new workflow is proposed to enhance vertical permeability estimation through resistivity anisotropy modeling, while also correcting Sw (water saturation) for resistivity anisotropy effects. Permeability anisotropy (Kh / Kv) was measured in core samples taken from a vertical pilot hole and correlated with the resistivity anisotropy (Rv / Rh) inferred from inversions of LWD resistivity data in offset lateral wells. Also, by modeling phase-shift and attenuation resistivity measurements in the laterals, true horizontal resistivities are estimated and then used to obtain a more accurate Sw (water saturation). The Rv / Rh ratio of the laterals is used to infer Rv / Rh in the verticals and to generate the final Kh / Kv transform in the laterals. The corrected Sw as well as the estimated Kh / Kv ratio in the laterals are used as inputs to the field reservoir modeling. Traditionally, when history matching waterflooded Natih reservoirs, the vertical permeability was assumed to be a fraction of the horizontal reservoir permeability. A Kv / Kh ratio, typically in the range of 0.1 to 0.3, was applied throughout the model. In the absence of core measurements, the Kv / Kh ratio was iteratively adjusted through trial and error, until a reasonable match of the historical production and injection data was achieved. The process was time-consuming, especially when history matching a large field. Through this new workflow, vertical permeability was estimated as an independent and variable reservoir property on a foot-by-foot basis along each lateral of the field. The new independent permeability was tested as an input in a dynamic model of a Natih reservoir in Oman, yielding results comparable to the traditional approach while significantly reducing the time to achieve history match.

A new absolute permeability upscaling method based on geological hierarchical models that affect different scales reservoir heterogeneities is presented. Reservoir anisotropy is evaluated via horizontal permeability (Kh) and vertical permeability (Kv). The new approach based on the geologic viewpoint that various geologic hierarchical-elements set result in relevant permeability display of different reservoir scales. For reservoirs, from micro-scale to macro-scale, influencing factors of permeability become abstruse. In conventional scenario, the calculation method based on single-phase numerical simulation test, core analysis and data statistics integrates all these factors as much as possible to upscale permeability. Considering reservoir anisotropy, horizontal permeability (Kh) and vertical permeability (Kv) are studied to show how anisotropy changes according to different reservoir heterogeneities. In the case study of Mackay River Oil Sand Block, Alberta, Canada, database includes regional depositional setting, core, and logging data for more than 20 wells. Generally, reservoir sedimentary setting poses a direct effect on permeability. Local rock bedding affects permeability anisotropy greatly, as well. There is no obvious linear parity between horizontal permeability (Kh) and vertical permeability (Kv) in core-plug. Vertical and lateral grain size variance also alters permeability. The mm-cm scale mud drapes have a worse effect on vertical permeability (Kv) than on horizontal permeability (Kh). Besides, bioturbations in the transitional facies could be favor of permeability. The three factors have non-linear relationship on effecting permeability. The new upscaling model synthesizes all these factors to upscale the permeability for nearly all scales of reservoirs, from the scale of core to lithofacies or even to the entire reservoir. Comparisons study is also conducted between this model and current upscaling algorithms such as arithmetic average, harmonic average, etc. The results showed that the upscaling model of this paper is more reasonable. Meanwhile, reservoir characterization hierarchical models can also be applied to explicate heterogeneity effect on the attribute of reservoir fluid qualitatively. The novelty of this approach lies in solving reservoir fluids' attributes quantitatively through exact heterogeneities analysis.

Актуальность работы. Значительная доля разрабатываемых нефтяных активов, приуроченных к карбонатным сложнопостроенным объектам, заметно возросла как на территории России, так и в Пермском крае. Достоверное знание параметров трещинно-порового типа коллектора позволяет уточнить действующие геолого-гидродинамические модели, подобрать рациональную систему разработки, регулировать процессы разработки и обеспечить для данного пласта оптимальные геолого-технические мероприятия. При построении и адаптации геолого-гидродинамических моделей нефтяных месторождений, особенно относящихся к сложнопостроенным карбонатным коллекторам, важное значение имеет знание как горизонтальной, так и вертикальной проницаемости (параметра анизотропии). При создании геолого-гидродинамических моделей карбонатных объектов месторождений Пермского края зачастую вертикальную проницаемость принимают равной нулю, хотя это далеко не так. Определение вертикальной проницаемости (параметра анизотропии), ее динамика при изменении пластового и забойного давлений и использование в геолого-гидродинамических моделях является актуальной задачей, которая позволит повысить качество и достоверность использования цифровых моделей для расчета и прогнозирования процесса добычи нефти. Цель: совершенствование геолого-гидродинамических моделей с учетом использования показателя анизотропии проницаемости. Объект: карбонатная фаменская залежь Гагаринского месторождения. Методы:обработка данных геолого-промысловых исследований; использование гидродинамического симулятораTempest версии 8.3.1 компании Roxar. Результаты. По предложенной в статье методике определения параметра анизотропии обработаны 252 исследования, проведенные на добывающих и нагнетательных скважинах фаменской залежи Гагаринского месторождения. Для каждой литолого-фациальной зоны построена зависимость показателя анизотропии проницаемости от забойного давления. Для прогнозирования и оценки эффективности применяемых геолого-технических мероприятий и технологических показателей разработки авторами статьи модифицирована геолого-гидродинамическая модель с учетом полученных зависимостей об изменении параметра анизотропии. С помощью модифицированной гидродинамической модели удалось значительно улучшить адаптацию как по добывающим, так и по нагнетательным скважинам. Таким образом, повысилось качество и достоверность цифровой модели фаменской залежи Гагаринского месторождения для расчетов и прогнозирования процесса добычи нефти.

This research presents the results of compaction grouting tests to investigate the effects of injection depth and injection rate on cavity shape and expansion. The one-stage injection tests use real compaction grout injected into a dry, cohesionless soil. The soil response due to injection is evaluated with respect to the injection pressure during grouting and the degree of compaction in the surrounding soil. The results of the experimental program have previously shown that the final shape and volume of the grout bulb and the minimum overburden above which compaction grouting is no longer efficient is dependent primarily on injection depth and grout composition, and to a lesser degree, injection rate, and soil type. The results of this phase of research show that the overburden pressure and injection rate have an effect on the pressure required to initiate and sustain cavity expansion and grout bulb development.

Natural gas hydrate is regarded as a highly promising clean energy source with significant development potential. The permeability anisotropy of the hydrate-bearing layer (HBL) significantly impacts production performance of hydrate reservoirs. Through numerical simulations calibrated with Site SH7 geological data from the Shenhu Area, South China Sea, this study investigates the effects of the HBL permeability anisotropy on production performance and dissociation behavior in hydrate reservoirs. In typical laminated sedimentary reservoirs, horizontal permeability parallel to bedding planes promotes horizontal connectivity, increasing cumulative gas production and rates. Meanwhile, preferential horizontal dissociation of hydrate can markedly enhance the gas–water ratio, improving the production performance of reservoirs. Conversely, vertical permeability dominance initially enhances vertical gas migration but diverts gas into non-production layer, reducing long-term production and rate. Increasing either horizontal or vertical permeability enhances fluid mobility within the HBL, thereby boosting cumulative water production and rate. Additionally, permeability anisotropy governs the spatial distribution of pressure-temperature fields and the expansion direction of the dissociation front, forming horizontal or vertical low hydrate saturation zones and gas-aqueous enrichment regions. This study demonstrates that horizontal permeability optimization serves as a critical determinant in enhancing gas production performance, providing actionable strategies for optimizing the exploitation of hydrate reservoirs.

Steam Assisted Gravity Drainage (SAGD) is the dominant oil recovery method to extract heavy oil and bitumen in sandstone and tarsand in Canada. There are plenty of publications studying SAGD mechanism and the effects of some reservoir and operating parameters on this process. These factors mainly include steam injection rate and pressure, well placement, vertical and horizontal permeability, barriers, conductive fracture, porosity and pay zone thickness. According to authors literature review, there is not any published study to investigate the effect of lateral variation of vertical permeability on SAGD mechanism and performance. This paper is a numerical effort to study influence of lateral variation of vertical permeability on SAGD mechanism and performance. In this paper some types of lateral variation of vertical permeability are considered to examine their influence on the process. Compared to uniform permeability case, the case with lower vertical permeability in parts far from the wells shows no change in oil recovery pattern. The case with lower vertical permeability near the wellbore region and the same vertical permeability in parts far from wells results in lower oil recovery till late time of process. Declined permeability to the given extent in middle region with the length of 30 m is the critical length longer which does not have any impact on the oil recovery. While the vertical permeability has considerable effects on oil recovery, associated horizontal permeability also has remarkable impact if happened in near wellbore region. Based on the results, it is concluded that in early time of the process that steam chamber propagates upward, convention has a very important role in heat transfer to reservoir, however, in late time that steam chamber moves sideways, conduction has also an important role in reservoir heating. This work has some evidences revealing the role of convention and conduction in reservoir heating in various steps of SAGD process.

For a reservoir having a low vertical permeability, tests in a single well can be carried out to determine the value of the permeability, both normal and parallel to the bedding plane, and horizontal as well as vertical. The calculations can be performed with the aid of only a slide rule. Introduction Knowledge about the average vertical permeability of oil and gas producing formations is sometimes necessary to anticipate properly the production performance of a reservoir. performance of a reservoir. Other than the use of vertical permeability measurements on cores recovered from a formation, the only method available at present for determining the vertical permeability of a formation' from a single well requires the use of a numerical simulator, which is not generally available to the practicing engineer. This is in contrast to the numerous desk-type methods for analyzing pressure responses to obtain the average horizontal permeability of reservoirs. A desk-type method is proposed for measuring the average vertical permeability of the formation near a well. The method, which can be applicable only to some wells, consists of producing (or injecting) fluid at a constant mass rate of flow through a short interval (even a single perforation) near the top or bottom of a formation and in measuring the pressure response through another short interval in the same well (packed off from the first) without producing or injecting fluid through the latter openings. The idealization made in developing the method is discussed in the next section. Our approach differs from that followed by Bums' in that no digital computer is required to interpret the pressure response curve; rather the interpretation is based on results that are presented simply in a single graph. presented simply in a single graph. Description of Method of Solution The reservoir is considered to extend horizontally from the wellbore to infinity, to be of uniform thickness h, to be filled with a single mobile liquid of constant compressibility c and viscosity u at an initially uniform pressure pi, and to have uniform porosity 0. Permeability anisotropy is considered, one of the Permeability anisotropy is considered, one of the principal axes being vertical. In the horizontal plane, principal axes being vertical. In the horizontal plane, permeabilities are equal in all directions, whereas the permeabilities are equal in all directions, whereas the vertical permeability kv can have any (constant) value. The problem is to measure kv in situ. It is clear that any method that aims at determining the average vertical permeability of a formation must involve vertical fluid flow over the region of interest. In operating practice in the field, fluids generally flow parallel to the bedding rather than normal to it. It is parallel to the bedding rather than normal to it. It is evident then that a test procedure involving the vertical flow of fluid needs to be developed in order to determine the average vertical permeability of a formation. We chose withdrawal or injection of fluid from a reservoir through a single perforation as the easiest way to obtain some vertical flow in the neighborhood of the well. And we chose making a second perforation, separated from the first by a packer, as perforation, separated from the first by a packer, as the easiest way to permit measuring the vertical pressure response. Production of fluids through the pressure response. Production of fluids through the perforation used to measure the pressure response is not perforation used to measure the pressure response is not necessary. JPT P. 637

Oscillation of a transient bubble between two parallel plates with cylindrical bulges

Anisotropic permeability and bimodal pore-size distributions of fine-grained marine sediments

Nowadays acidizing became one of the most common approaches used to increase the hydrocarbons production from carbonate reservoirs. An acid solution injected under pressures below the formation fracture pressures dissolves the rock matrix and, thus, facilitates the fluid flow. However, the overall treatment efficiency is crucially dependent on the acid composition and injection scenario, since the different dissolution patterns are created depending on the effective reaction rate (i.e. acid composition and matrix mineralogy) of the reactive fluid and the fluid injection rate. At slow injection rates, when the acid is spent before penetrating deep into the rock, the face dissolution scenario is observed. On the other hand, fast injection results in uniform distribution of the acid along the treatment zone and similar uniform dissolution of the matrix. The best result from production improvement point of view is achieved when the acid creates a set of thin channels - the so-called wormholes. This optimum regime corresponds to the minimum in the pore volume to breakthrough (PVBT) dependence on injection rate (Fredd, 1998; Zhang, 2021). Where PVBT is defined as the amount of treatment fluid (measured in core pore volumes) required to be injected before the appearance of macroscopic flow channel linking the opposite faces of the core. Thus, since the optimal acid composition and the injection rate are determined by geology and lithology of the reservoir, to achieve the best effect, each treatment should be preceded by experiments on representative rock samples. In addition to that, the parameters to be optimized for a typical acidizing job also include the sequence of injected fluids and the amount of the fluid to be injected (Yudin A., 2021), which requires an extensive laboratory study. Unfortunately, the amount of the core material available is usually not sufficient for such a comprehensive laboratory analysis. Moreover, the destructive nature of acidizing experiments imposes the fundamental limitation: experiments are performed on different core samples, which makes the results less conclusive.

Local drug delivery aims to minimize systemic toxicity by preventing off-target effects; however, injection parameters influencing depot formation of injectable gels have yet to be thoroughly studied. We explored the effects of needle characteristics, injection depth, rate, volume, and polymer concentration on gel ethanol distribution in both tissue and phantoms. The polymer ethyl cellulose (EC) was added to ethanol to form an injectable gel to ablate cervical precancer and cancer. Tissue mimicking phantoms composed of 1% agarose dissolved in deionized water were used to establish overall trends between various injection parameters and the resulting gel distribution. Additional experiments were performed in excised swine cervices with a CT-imageable injectate formulation, which enabled visualization of the distribution without tissue sectioning. Needle type and injection rate had minimal impact on gel distribution, while needle depths ≥13 mm yielded significantly larger distributions. Needle gauge and EC concentration impacted injection pressure with maximum gel distribution achieved when the pressure was 70-250 kPa. Injection volumes ≤3 mL of 6% EC-ethanol minimized fluid leakage away from the injection site. Results guided the development of a speculum-compatible hand-held injector to deliver gel ethanol into the cervix. Needle depth, gauge, and polymer concentration are critical to consider when delivering injectable gels. This study addressed key questions related to the impact of injection-based parameters on gel distribution at a scale relevant to human applications including: 1) how best to deliver EC-ethanol into the cervix and 2) general insights about injection protocols relevant to the delivery of injectable gels in tissue.