Well testing, Reservoir characterization

The Wasabizawa geothermal field is located in Akita prefecture, northeastern Honshu. Commercial operation of the Wasabizawa geothermal power station (46.199 MWe) began in 2019. The subsurface stratigraphy consists of a sequence of volcanic rocks overlying naturally-fractured granitic basement rocks. The geothermal reservoir is hosted by the naturally-fractured granitic rocks. Fault systems striking along NW-SE, NE-SW and E-W trends are inferred by geophysical surveys (gravity survey and MT & CSAMT surveys). Targeting these estimated fault zones, a total of 11 production and reinjection wells, in addition to five existing exploration wells which will be converted to production and injection wells, were drilled during construction of the power station, and an extensive heterogeneity of fracture distribution in the granitic basement rock was observed. To delineate the permeability structure for the area, numerous pressure transient tests were performed during short term production from...

In most of the oil production processes exist an interaction between fluids flow and mechanical behavior stress-deformation in porous media. On the other hand, reservoir modeling has evolved toward numerical techniques (meshing) and fluids flow physical complexity, giving less importance to the reservoir's solid mesh. However, there are some worldwide fields where solid mesh's geomechanical results are important to understand the reservoir behavior and to design the appropriate recovering mechanism. Some examples of this are dolomitic reservoirs in California and non consolidated sand reservoirs in Venezuela and Canada, and so pressurized reservoirs in the North Sea and the Mexican Gulf.

Given the crucial role of oil in industries and daily life, along with the insufficiency of alternative fuel sources, various efforts have been made to maximize hydrocarbon recovery from reservoirs. One of the persistent challenges in producing reservoirs is the low permeability around the wellbore and the formation damage affecting the reservoir rock. To address these issues, well stimulation techniques are employed to enhance production. In Iran, where more than 80% of reservoirs are carbonate, acidizing is widely used for stimulating oil and gas wells. In contrast, in sandstone reservoirs, acidizing often fails to yield satisfactory results, making hydraulic fracturing the preferred method. This study first examines different acidizing systems, the types of acids used in acidizing processes, and the key factors influencing acidizing outcomes, with a specific focus on fractured carbonate reservoirs and their acidizing mechanisms, particularly the interaction between fractures and the matrix. To provide an operational perspective on these concepts, the research also reviews case studies conducted by Iranian researchers, analyzing changes in parameters such as pressure, skin factor, permeability, and production rate resulting from successful acidizing operations in oil wells located in the Persian Gulf region.

Permanent Downhole Monitoring Systems have now become a standard component of well completion. The processing and interpretation of continuously recorded downhole pressure and temperature data provide static and dynamic reservoir characteristics, which can be used to develop and optimize production processes. This paper explores the applications of data from these systems for well testing, determining reservoir permeabilitythickness, wellbore skin, static reservoir pressure, identifying fractures and barriers, optimizing initial production, waterflooding, and enhanced oil recovery (EOR). Additionally, by developing models, this data can be used to estimate production rates and gas-oil ratio (GOR). Simulated models can be calibrated with continuous data, such as pressure, production rates, and GOR, resulting in higher accuracy compared to conventional methods that rely on estimated data. The use of downhole sensors not only directly reduces production costs but also enables optimal and sustainable reservoir production, thereby improving the recovery factor.

The present research is aimed at exploring the B1.1 sandstone sequence
located in the lower Miocene formation within the Bao Den oilfield situated
in the Cuu Long basin. This study involves utilizing Pressure-VolumeTemperature well parameters, such as bubble pressure, oil gas ratio, oil
formation volume coefficient, density, viscosity, total compressibility, and
BI.1 sandstone sequence parameter, including effective thickness, average
porosity, well radius, and water saturation. Our focus will be on analyzing
reservoir tests with two methods - the conventional and progressive
approaches. This study will examine the Horner graph and how it can be
used with formulas for determining initial reservoir pressure, slope, and
fluid conductivity as part of the traditional method. Additionally, effective
permeability, skin coefficient, and conductivity will also be analyzed. The
advanced method involves using Ecrin software to interpret results, which
shows that both methods yield favorable skin coefficients. The outcomes
indicate that the well and reservoir parameters are precisely determined: the
initial pressure of the reservoir is 2617.5 psia, hydro conductivity equals
7680 mD.ft, while permeability is 106 mD, coefficient Skin is 14, well
storage coefficient evaluates to 5.61E-4
and distance to fault 439 ft. Based
on the results, it is possible to assess that the BD-1X well in the Bao Den
oilfield has promising potential as both oil and gas have favorable quality
and volume attributes. This study's significance is providing input data for
developing and exploiting oil fields resulting in choosing economical plans
with commercial efficiency within the petroleum industry.

We propose a rigorous approach for well drainage volume calculations in gas reservoirs based on the flux field derived from dual porosity finite-difference simulation and demonstrate its application to optimize well placement. Our approach relies on a high frequency asymptotic solution of the diffusivity equation and emulates the propagation of a 'pressure front' in the reservoir along gas streamlines. The proposed approach is a generalization of the radius of drainage concept in well test analysis (Lee 1982), which allows us not only to compute rigorously the well drainage volumes as a function of time but also to examine the potential impact of infill wells on the drainage volumes of existing producers. Using these results, we present a systematic approach to optimize well placement to maximize the Estimated Ultimate Recovery. A history matching algorithm is proposed that sequentially calibrates reservoir parameters from the global-to-local scale considering parameter uncertainty and the resolution of the data. Parameter updates are constrained to the prior geologic heterogeneity and performed parsimoniously to the smallest spatial scales at which they can be resolved by the available data. In the first step of the workflow, Genetic Algorithm is used to assess the uncertainty in global parameters that influence field-scale flow behavior, specifically reservoir energy. To identify the reservoir volume over which each regional multiplier is applied, we have developed a novel approach to heterogeneity segmentation from spectral clustering theory. The proposed clustering can capture main feature of prior model by using second eigenvector of graph affinity matrix. In the second stage of the workflow, we parameterize the high-resolution heterogeneity in the spectral domain using the Grid Connectivity based Transform to severely compress the dimension of the calibration parameter set. The GCT implicitly imposes geological continuity and promotes minimal changes to each prior model in the ensemble during the calibration process. The field scale utility of the workflow is then demonstrated with the calibration of a model characterizing a structurally complex and highly fractured reservoir. iii DEDICATION This work is dedicated to my wife, JuYoun Han, who has been the support and motivation during the good and difficult times during my four years of Ph.D. degree period in Texas A&M University. This dissertation is not just my work. We made it together. iv ACKNOWLEDGEMENTS I would like to thank my committee chair, Dr. Akhil Datta-Gupta for all his support during my Ph.D. studies. His guidance and insightful view have been the foundation of my work. He also has provided economic support and an industry perspective through the joint industry project. Also, I want to thank all my committee members, Dr. John Lee, Dr. Michael King and Dr. Efendiev. Your comments and questions have been invaluable to look at the problem from multiple perspectives. Thanks, also, go to my friends, colleagues and the department faculty and staff for making my time at Texas A&M University a great experience. Especially, I want to acknowledge Eric, Jiang, HanYoung and JongUk for all the valuable discussions through the different stages of my research. I want to extend my gratitude to Hopcus, Phaedra who has supported and helped MCERI students. I would like to thank my friends: Alvaro,

In this research, water injection into a reservoir is used as one of the methods for enhanced oil recovery in hydrocarbon reservoirs. In this study, a single-phase water flow is injected into the reservoir, and production is carried out from the four corners of the reservoir using production wells. The Darcy pressure equation in a porous medium is discretized using a finite difference method with a grid of 1650 cells for numerical solution. The flow simulation in this porous medium was performed using a computational Fortran code over a period of 500 days, and the results were analyzed. The flow rate and pressure of the wells in compressible and incompressible states, with and without considering capillary effects, were calculated and compared using both the classic and improved IMPES methods. One of the key findings is the flow rate variation over time in compressible versus incompressible states, which shows that in the incompressible case, the flow rate and pressure are less dependent on time. Additionally, the simulation results were validated against CMG software results to ensure accuracy. This problem was solved using a Fortran code.

In this work, we have investigated the well pressure distribution in a bounded circular reservoir under the condition of constant pressure outer boundaries. The diffusivity equation was used in the analysis. The finite element technique, using Lagrange quadratic shape elements was employed to carry out the analysis over the cross-section of the reservoir which involves discretizing the domain into finite element, analysing these finite element, assembling the results from the analysis of the analysed finite element, imposing the boundary conditions and finally, getting the results that represent the entire domain. The results obtained where shown in a log log plot (dimensionless pressure against dimensionless time) for dimensionless radii of 1 to 1,000,000 in log cycles. It was shown that the relationship between dimensionless pressure and dimensionless time was linear whose slope was zero. The result obtained at the wellbore was compared with the results obtained by Van Everdigen and Hurst. It was shown that there was a strong positive correlation between the results. The result obtained from the analysis also shows the pressure variation outside wellbore of the same reservoir. It is important to note that solutions from existing literature only state the pressure at the wellbore at a particular time but this work predicts the pressure variation in the entire reservoir from the wellbore to the external boundary at the same time.

In this first Chapter, the terminology used in well testing and interpretation is presented, and different testing procedures are explained. In the second part, characteristic well pressure behavior is illustrated, and the corresponding analysis methods are introduced. It is shown that well test responses follow chronological characteristic behavior at different times, depending upon the well and reservoir configuration. The interpretation techniques are presented in detail in the following Chapter 2. 1.1 Principles of transient testing When the well is shut-in, the build-up pressure change Ap is estimated from the last flowing pressure p(At=O):

This research is focused on scaling of a radial turbine for turbocharger of a lean combustion engine. One of the methods to decrease pollution is to reduce the exhaust temperature using lean combustion. So, more air should be entered the engine, and by increasing the air, the turbocharger should be changed for increased mass flow rate. In the first step, the turbine performance is simulated using a CFD solver, and the results are compared to the experimental data. Next, the turbine is scaled by four scenarios, and the turbines' performance is simulated using the CFD solver. In the first scenario, only the hub radius is decreased, and the mass flow is increased by 0.5%. In the second scenario, the hub radius decreases, and the shroud radius increases, and a 7% improvement is obtained. In the third scenario, the inlet and shroud radius increase while the hub radius decreases, and the mass flow is improved by 11%. In the fourth scenario, the geometry is changed freely, and a 20% increment is obtained.

The purpose of the well test analysis is to identify the type of reservoir involved and to determine the parameters of the reservoir quantitatively. The assessment of the properties and capacity of geothermal resources involves various kinds of logging tests, data interpretation, monitoring, and modeling. This ranges from the analysis of data collected during the heat-up and testing of single wells to the simulation of the response of the geothermal reservoir to utilization over years or even decades. This paper presents a comprehensive review of the theoretical background and methodology used in analyzing injection-falloff test, temperature and pressure logging data from the Sabalan geothermal wells, as well as a review of the methods generally used for geothermal reservoir pressure response modeling and analysis. Data from three Sabalan wells were analyzed using the computer software Well Tester developed by ÍSOR – Iceland GeoSurvey. The results of well test analysis for well NWS-5 are presented in this paper.

Simulation of geothermal fracture reservoirs is a difficult task both due to the description of the reservoirs and numeric methods. The flow rate of geothermal fluid production from a fractured reservoir is a function including several variables; size and specifications of the blocks of matrix and the saturation of the fraction system. The double porosity method assumes that the porous fractured layer can be shown by two overlapping connected systems that are called fraction and matrix. The fractured part constitutes some connected fractions together with vugs that make the primary ducts for the fluid current. The matrix is also constructed of porous spaces of stone that contains the biggest share of the supply of the reservoir. In this field, after obtaining the conformity of the log and adjusting the reservoir parameters and completing the dynamic model, its future conditions were studied. To do so, according to the current conditions regarding the number of the wells, well testing and well logging results, separator conditions and the steam flow rate of production, different production and reinjection methods were studied aiming at determining the best production scenario.

Actualmente se han aplicado diferentes tecnicas para incrementar la productividad en pozos del APATG, todo esto con la finalidad de incrementar la produccion y el factor de recuperacion en yacimientos turbiditicos de baja permeabilidad. Estas incluyen desde refracturamientos y multifracturamientos en pozos verticales, hasta la creacion de redes complejas de fracturas en pozos horizontales, que han ayudado a incrementar la produccion inicial y reducir su declinacion. El comprender la complejidad del yacimiento es el primer paso para su correcta evaluacion, al analizar el mismo de una forma no convencional, para ello se debe de realizar un analisis de forma integral con equipos multidisciplinarios y herramientas especializadas para aplicar tecnicas de terminacion innovadoras como el refracturamiento, multifracturamieto y redes complejas de fracturas en pozos horizontales, logrando el exito de produccion planeado. Estas tecnicas abren un panorama de posibilidades al tener resultados su...

Dos pruebas de inyección de CO2 son ejecutadas entre el 19 de julio de 2010 y 31 de marzo del 2011. El propósito: encontrar formas de incrementar la recuperación de aceite en campos de la Formación Chicontepec. La primera es una prueba de inyección continua que involucra un pozo inyector y seis productores de la macropera Coyotes 331, del campo Coyotes. En 166 días, 197 MM scf CO2, equivalentes a 93,850 barriles de espacio poroso, ó 1.1 veces el volumen de líquidos producido por los 7 pozos de la macropera a junio de 2010, son inyectados. Un pozo, el Coyotes 312, reacciona a la inyección. Sin
embargo, contrario al orden establecido en flujo continuo: ascenso de presión, incremento de producción e irrupción, el pozo manifiesta surgencia temprana, paulatino incremento de presión y cero cambio en la declinación. En los otros, la declinación permanece sin cambio, composicionalmente el aceite no acusa variación. El que ninguno de los pozos productores haya respondido favorablemente a la inyección sugiere la idea de un yacimiento segmentado en el cual lentes areno arcillosas, impregnadas de aceite y aleatoriamente distribuidas estarían rodeadas por roca estéril, impermeable al flujo de aceite, que no de gas. Reforzada por las experiencias adversas de las pruebas de inyección de agua, tal apreciación llevaría a replantear la prueba de inyección en otra dirección.

This paper presents an analysis of gas well production forecasting and pressure dynamics within natural gas formations. Focused on transient flow conditions and assuming Darcy flow with zero skin factor, the study delves into two key aspects: production forecasting and pressure drop analysis. The primary objective is to develop a production forecast until the average reservoir pressure declines to 2,000 psi. Additionally, the paper examines the pressure drop along the well, detailing its components including friction, acceleration, and gravitational potential, with depth profiles presented for at least one average reservoir pressure scenario. The analysis also considers temporal variations in pressure drop, providing insights into how these dynamics evolve over time. Through rigorous examination and discussion, this study offers valuable insights into optimizing gas well production strategies and understanding pressure behavior in natural gas formations.

The conventional phase behavior study of petroleum reservoir fluids are valid when the reservoir temperature is far enough from the critical condition in which the material balance equation can be applied correctly. When the temperature of the reservoir is in the vicinity of the critical temperature the classical methods can't determine the phase behavior of the mixture due to rapid phase change below the saturation pressure. A small change in pressure will cause forming large amount of either liquid or gas phases. In this paper one of the Iran near critical reservoir fluid has been studied. A proper method for laboratory study of these fluids has been developed. Also the results show that the commercial software don't work properly on these fluids. Based on the results of this study the production strategy of the reservoir has been changed.

The analysis of pressure tests in geothermal reservoirs is often complicated by two-phase effects. This paper investigates the effect of a phase boundary at a constant radial distance from the well, produced, for example, by the flashing of a water reservoir during production or by the injection of water into a steam or two-phase reservoir. This configuration may be recognized from a time shift in the buildup (or falloff) semilog straight line, and, in some cases, the distance to the phase boundary can be estimated by plotting the transition pressure response against time on cartesian coordinates. Field data from the Broadlands geothermal field in New Zealand confirms the applicability of the technique and demonstrates that the injected volume (which is known) may be used with the buildup data to calculate porosity and "swept" volume. The analysis also indicates the possibility of determining compressibility and permeability contrasts across the phase boundary. This enables estimation of the reservoir porosity and relative IP~h;l; in the two-phase region. In a few cases, wellbore storage effects can disguise the pressure response and make parameter determination more difficult. These cases are discussed.

El Shale gas es simplemente gas natural, compuesto generalmente de 90% de metano. Su nombre se debe a su procedencia, el esquisto (o Shale en inglés). Durante la última década este recurso se ha convertido en una fuente de energía cada vez más importante en los Estados Unidos, y el interés se ha extendido a Canadá, Europa, Asia, Australia y ahora, Latinoamérica. Debido a que los Shales no tienen suficiente permeabilidad para permitir el flujo de fluidos de forma significativa, la mayoría de estos Shales no son fuentes comerciales de gas natural y se denominan recursos no convencionales, al igual que el gas asociado a mantos de carbón, las arenas apretadas y los hidratos de gas. Debido a las condiciones que presentan este tipo de yacimientos, la viabilidad económica de su explotación económica requiere necesariamente la implementación de tecnologías de pozos horizontales combinadas con técnicas de fracturamiento hidráulico. Con el fin de optimizar los parámetros operacionales, los cuales son indispensables para garantizar el éxito de la explotación y evaluar el desempeño de este tipo de reservorios, es muy usual realizar pronósticos de producción a partir de la simulación de yacimientos. El conocimiento del posible comportamiento futuro de un yacimiento de Shale gas permite determinar la viabilidad de los proyectos, las estimaciones económicas y el incremento de la producción esperada. En este artículo se realiza el modelado numérico y analítico para un Single Well Model de shale gas con el fin de cuantificar el gas in place, el EUR de estos yacimientos y determinar la viabilidad económica al momento de explotar estos plays.

The CP-52 and CP-54 wells are located on the Tambun structure of Bekasi Regency of West Java Province with the target formation being Baturaja. The pressure build up analysis is carried out for monitoring activities to obtain reservoir and boundary, innitial pressure (Pi), permeability (k), skin (s), ΔP skin, average pressure (Pavg), and flow efficiency information. Tests performed on both wells are pressure build up test (PBU) and to analyze the method of Horner approach pseudo pressure and P2 either manually or with the help of software v.ex.2 v2.02 as validation.

Summary We present a formulation for a fractal fracture network embedded into a Euclidean matrix. Single-phase flow in the fractal object is described by an appropriate modification of the diffusivity equation. The system's pressure-transient response is then analyzed in the absence of matrix participation and when both the fracture network and the matrix participate. The results obtained extend previous pressure-transient and well-testing methods to reservoirs of arbitrary (fractal) dimensions and provide a unified description for both single- and dual-porosity systems. Results may be used to identify and model naturally fractured reservoirs with multiple scales and fractal properties.

Este trabajo propone una solución para poder lograr mayor conectividad dinámica entre yacimientos compartimentalizados. La propuesta consiste en comunicar a través de pozos horizontales, las zonas o regiones de un yacimiento en donde se ha detectado la compartimentalización. El flujo de hidrocarburos entre los compartimentos se producirá debido a la diferencia de potencial existente entre ellos. El gasto volumétrico de los fluidos transferidos dependerá principalmente del diseño del pozo horizontal, así como de las propiedades petrofísicas del yacimiento y propiedades físicoquímicas de los fluidos. En el trabajo presente se desarrolla un modelo matemático que representa el comportamiento del potencial de cada compartimento a través del tiempo, cuando se comunican mediante un pozo horizontal. Se considera la aplicación especial en sistemas con capa de gas y se presenta un ejemplo que demuestra el impacto y los beneficios de esta solución. La aplicación de esta propuesta permite explotar hidrocarburos que no han sido drenados debido al efecto de la compartimentalización, a través de la infraestructura existente en las regiones adyacentes; por lo tanto, se puede reducir o eliminar el requerimiento de nueva infraestructura y de esta forma, se amplía la vida útil de la infraestructura existente, logrando así maximizar el valor y la recuperación de los campos, lo cual representa grandes beneficios económicos.

Determining the contact surface of fluids is one of the challenges of field development planning and reservoir management. From a thermodynamic point of view, the gas-oil contact is the deepest place where the most fluid composition changes occur so that the depth of a discontinuity takes place there because of the instantaneous phase change at the contact surface. This instantaneous phase change can originate from gravitational, chemical, and thermal forces. In this study, simulation was performed using Eclipse and Petrol software. To perform this simulation, first the initial contact surfaces as well as the changes in the contact surface during the production history determined from pressure test experiments and production logs were used. Then changes in water-oil and gas-oil contact levels were predicted for future years of production. Considering the surface distribution of water-oil contact, it can be understood how deep the water-oil contact surface has expanded in each area of the reservoir. By studying this water-oil contact surface, it is possible to increase the prediction accuracy of the drilling location of the new wells and the potential dangers (water conning).

Enhanced oil recovery is one of the most crucial steps in production from hydrocarbon reservoirs, and shale reservoirs are one of the most important unconventional hydrocarbon reservoirs. Shale gas resources are formed in shale rocks, and source rock, reservoir rock, and cap rock are the same in these reservoirs. To expand shale gas reservoirs, techniques for creating artificial fractures around the wellbore are applied. Production from oil and gas reservoirs will be followed by a pressure drop in them. By production in condensate reservoirs, the pressure can be reduced to below the dew point. As a result, condensate will be produced in the reservoir, especially in the area around the wellbore. This considerably reduces gas production. There are several ways to alleviate this problem and enhance recovery from shale gas reservoirs including thermal and chemical methods, gas injection, water injection, drilling horizontal wells, hydraulic fracturing, CO2 injection, and nitrogen injection. Some of these techniques are investigated and analyzed in this research.

Well completion engineering is one of the most important and effective branches in petroleum engineering and also one of the most challenging tasks after the completion of a well drilling operation. There are various methods to complete the well, but the oil engineering team must choose the most effective way to complete the well according to the characteristics of the reservoir, operating conditions of the well, and technical and economic issues. In this study, it has been tried to introduce the types of well completion methods, the types of completion string and the arrangement of these parts in the well, to implement a completion program in such a way as to enable maximum production for a long time with minimum cost.

Este artículo presenta un método para analizar pruebas de variación de presión con rasgos diferentes de los más comunes que denotan geometrías de flujo lineal, radial o esférico, y que son indicadores de flujo de tipo fractal en el yacimiento. El método utiliza una solución a la respuesta de presión con flujo de tipo fractal en el dominio de Laplace e incluye los efectos de daño y almacenamiento por medio de un procedimiento usado para la descripción del flujo en geometrías compuestas. Este enfoque es más sencillo que los presentados en artículos anteriores a éste. La determinación de las propiedades fractales en aplicaciones a casos de campo da por resultado valores plausibles; para la comparación con valores reales es necesario conocer la distribución de las fracturas en el yacimiento.

Drill Stem Test (DST) describes the dynamic characteristic of the hydrocarbon bearing formation such as wellbore storage, skin effect, permeability, average reservoir pressure and reservoir boundary. The wellbore storage effect and average reservoir pressure help to predict the flowing phase from the reservoir. An effort has been made to analyze the DST conducted in the Kailashtilla field at the depth interval 3261 meter to 3266 meter in well KTL-7. Two sets of pressure profile have been recorded. First conditioning the well for an hour then performed drawdown following pressure build-up. The pressure signature of the buildup period and its derivative is plotted on semi-log and log-log coordinates to develop Horner and diagnostic plots, respectively. Wellbore storage, skin and transient flow effects have been observed in the DST analysis which is an indication of the hydrocarbon bearing reservoir in the zone of interest. The value of wellbore storage effect is low which predicts the...

Актуальность исследования состоит в том, что решением преждевременного прорыва воды или газа в горизонтальной скважине из-за неоднородности профилей притока вдоль оси горизонтального ствола, является изменение пластового давления на различных участках, а также при разработке контактных месторождений, особенно по мере истощения залежи, могут служить устройства контроля притока флюида. Различают активные Interval Control Valve (ICV) или пассивные Inflow Control Device (ICD) устройства. Устройства ICD способны выровнять приток вдоль горизонтальной скважины за счет создания дополнительного сопротивления потоку жидкости, зависящего от величины притока на данном горизонтальном участке. Недостаток современных ICD в том, что они не имеют возможности регулирования и приведения пассивных устройств в действие после установки в стволе скважины. В связи с тем, что имеются риски связанные с неопределенностью в описании свойств пласта, которые присутствуют на всех стадиях разработки месторождения ...

Conventional oil reserves are coming to an end, then, some unconventional sources, such as heavy oil, are being the aim of oil companies. Most of heavy oils, drilling fluids and fracturing fluids behave as non-Newtonian and these fluids are erroneously approximated by Newtonian fluid flow models. Currently, there are no mathematical expressions for the application of the straight-line conventional analysis method for the interpretation of pressure tests in heterogeneous or naturally-fractured occurring formations (dual porosity) which are saturated by a non-Newtonian pseudoplastic fluid. The literature includes an analytical solution for predicting the behavior of the pressure in dual porosity reservoirs containing a non-Newtonian fluid; this solution was subsequently used to interpret the well-pressure data using the pressure and pressure derivative log-log plot without employing type-curve matching. None commercial software includes up to date such analytical solution. Several expressions to complement the conventional straight-line method are presented in this work so pressure tests in naturally fractured reservoirs with a non-Newtonian power-law fluid can be interpreted. This is accomplished mainly by estimating the interporosity flow parameter and dimensionless storage coefficient. The developed equations were successfully tested using well pressure tests reported in the literature. Very good results were obtained from the worked examples when compared to the reference values.

This paper starts with an overview of the application of multiple-point statistics (MPS) to characterizing and modeling heterogeneous rocks with the aid of digital rock technology. An upscaling workflow from microscopic pore space to interwell scales is proposed and discussed by illustrative examples. In this MPS-driven upscaling workflow, training images, which play a key role in MPS modeling, are obtained directly from microscopic rock or borehole images or digital outcrops to capture more realistic heterogeneity of reservoir rocks and formations. Unlike the conventional upscaling method that typically applies a certain averaging scheme to coarsening a fine scale model, which tends to lose heterogeneous features that may be critical to fluid flow, the proposed workflow calls for both top-down and bottom-up approaches. The top-down approach aims to divide heterogeneous rock into different representative element volumes (REV) such that each one is more uniform or less heterogeneous; the bottom-up approach attempts to derive effective transport properties by carrying over the computed dynamic properties through running flow simulation from fine to coarser scales with the help of REV identification. This workflow allows us to couple the static with dynamic modeling to derive scale-dependent effective transport properties while capturing more realistic rock heterogeneity using MPS.

Conventional treatment of oil flow in porous media assumes that oil is in the typical range of flow velocity and pressure, and it behaves as a Newtonian fluid. This assumption, however, may not be accurate, especially for heavy oil. It is also not accurate in modeling injection behavior for fluids such as fracturing fluids, or polymer fluids for secondary recovery of oil. The literature contains articles that formulated and presented solutions of the posed fluid flow problem. When trying to apply the proposed solution methodology, the limitations of those techniques became apparent. Many authors have already pointed out the inapplicability of the presented techniques and suggested some corrections. Moreover the presented techniques are not valid for non-Newtonian fluids that have a power law index (n) greater than 0.6. In this paper we examine the solutions presented in the literature showing their limitations. We will examine the mathematical reasons for the problems and demonstrate rigorously that these (published) analysis techniques are impractical not only for real world problems but also for simulated data. Our in depth analysis explains away the problems analysts have had with the existing methodology. We also present a new reliable methodology for determining reservoir properties. The new methodology was tested on six real field data and two simulated datasets. The examples showed that the previously presented methodologies under-predict the permeability by at least 40%.

The heterolithic thin-bedded sand and shale are very commonly associated reservoirs column in shallow water clastic depositional environment in Malaysia Basin. The complexity in reservoirs characterization of heterolithic thin-bedded sand often leads to underestimating the potential contribution of these types of the reservoir for development and exploration targets. The naturally laminated of heterolithic thin-bedded sand make it more difficult in building the realistic 3D geological model and has an impact on volumetric calculation and reserve estimation. This study is applied in the development phase by introducing Log resolution enhancement methods in laminated thin-bedded sand characterization to quantify the reservoir potential with high-resolution 3D modelling methods. The quantification of sand and shale in thin bedded analysis using core data and image logs, then transform into lithofacies classification from sand and shale volume cutoff. The distribution and computation of lithofacies and reservoir properties build into a 3D model is obtained from a geological depositional environment analog at field-scale of a conventional setting. The results indicated high-resolution 3D geological modelling successfully preserved the characterization of thin-bedded sand and shale; and revealed an excellent correlation with the image log. The presence of inter-bedded sand and shale of reservoir column in the 3D geological model provides the quantification of thin-bedded sand contribution and potential realistic volumetric estimation for the entire reservoir interval. The thin-bedded reservoir characterization and high-resolution 3D modelling technique successfully address the existent of heterolithic reservoir facies previously simplified.

Gas injection serves as a main enhanced oil recovery (EOR) method in fractured-vuggy carbonate reservoir, but its effect differs among single wells and multi-well groups because of the diverse fractured-vuggy configuration. Many researchers conducted experiments for the observation of fluid flow and the evaluation of production performance, while most of their physical models were fabricated based on the probability distribution of fractures and caves in the reservoir. In this study, a two-dimensional physical model of the karst fault system was designed and fabricated based on the geological model of TK748 well group in the seventh block of the Tahe Oilfield. The fluid flow and production performance of primary gas flooding were discussed. Gas-assisted gravity flooding was firstly introduced to take full use of gas-oil gravity difference, and its feasibility in the karst fault system was examined. Experimental results showed that primary gas flooding created more flow paths and achieved a remarkable increment of oil recovery compared to water flooding. Gas injection at a lower location was recommended to delay gas breakthrough. Gas-assisted gravity flooding achieved more stable gas-displacing-oil because oil production was at a lower location, and thus, the oil recovery was further enhanced.

This study discusses the determination of the stabilized flow coefficient, C, in the Rawlins and Schellhardt equation. It is applicable in the reservoir with low porosity and permeability model, usually found in unconventional reservoirs. In determining the flow coefficient, a deliverability test method proposed by Hashem and Kazemi was used during the transient flow period of a gas well. Besides, in determining the deliverability exponent, n, used in the least squared analysis equation derived by Johnston and Lee in the determination of C stabilized so that from each value of n, there will be supporting data for determining stabilized flow coefficient. Finally, the application and previous method will determine the flow coefficient value based on reservoir model time stabilization. Later it compares with the John Lee equation and IPR constructs from the model and John Lee.

This study discusses the determination of the stabilized flow coefficient, C, in the Rawlins and Schellhardt equation. It is applicable in the reservoir with low porosity and permeability model, usually found in unconventional reservoirs. In determining the flow coefficient, a deliverability test method proposed by Hashem and Kazemi was used during the transient flow period of a gas well. Besides, in determining the deliverability exponent, n, used in the least squared analysis equation derived by Johnston and Lee in the determination of C stabilized so that from each value of n, there will be supporting data for determining stabilized flow coefficient. Finally, the application and previous method will determine the flow coefficient value based on reservoir model time stabilization. Later it compares with the John Lee equation and IPR constructs from the model and John Lee.

At present, when conducting an interference well test, a constant flow rate (at the 'active' well) is utilized, and the type-curve matching technique (where only 2-3 values of pressure drops are matched) is used to estimate the porosity-total compressibility product and formation permeability. For oil and geothermal reservoirs with low formation permeability, the duration of the test may require an extended period, and it can be challenging to maintain a constant flow rate. The qualitative term 'long' period means that (at a given distance between the 'active' and 'observational' well) more test time (for low permeability formations) is needed to obtain tangible pressure drops in the 'observational' well. In this study, we present working equations that will allow us to process field data when the flow rate at the 'active' well is a function of time. The shut-in period is also considered. A new method of field data processing, where all measured pressure drops are utilized, is proposed. The suggested method allows us to use the statistical theory to obtain error estimates on the regression parameters. It is also shown that when high precision (resolution) pressure gauges are employed, the pressure time derivative equations can be used to determine formation hydraulic diffusivity. An example is presented to demonstrate the data processing procedure.

A strongly heterolithic lithofacies from the lower part of the Tilje Formation is analysed using time-series analysis. We use, in addition to classical spectral analysis, a wavelet method that detects where in the time-series the periodic components are present. This allows us to evaluate the relative influence of various depositional processes as a function of time or depth. Based on the sedimentary structures, which are interpreted to be combined-flow ripple cross-lamination overlain by either graded rhythmites or fluid muds, and the time-series analysis, we attribute the detected periodic components to several (self-) oscillating processes. The transformation from depth-related data to time-related data is necessary to proceed from an observed geometric cycle to an interpreted time-cycle that can be related to an oscillating process. The periodic signal detected is related to a periodic increase in deposition of sand and mud dominantly supplied by a river system. At the shortest timescale , a semi-annual increase in river sediment supply is related to a tidal signal that influence the sediment distribution. Other self-oscillating processes, like seasonal variations in river discharge and deltalobe switching, are also interpreted to have influenced the sedimentary record. However, we realize that an exact reconstruction of the depositional history, based on the available data, is challenging both because several processes have operated simultaneously but also because it is difficult to assign a time-unit to each event. The vertical variation in sand fraction (which is the amount of the lithological clean sandstone component relative to the total rock volume) is also quantified by time-series analysis. We show, using published results on 3D bedform modelling, that the observed periodic variation in sand fraction will have a large influence on the permeability of these rocks. This shows that the incorporation of quantified geological data as predictable vertical variation in mud fraction will reduce the uncertainty of the reservoir model.

Данной работой авторы открывают цикл статей, посвященных методическим, технологическим, метрологическим и иным аспектам проведения и обработки результатов исследований PVT-соотношений пластовых нефтей различных физико-химических свойств. В настоящей работе представлен новый алгоритм обработки результатов ССЕ-теста пластовой нефти, предложены критерии валидации в целях контроля качества экспериментов. Применение алгоритма ограничено случаями исследований нефтей типа «black oil», то есть, пластовых углеводородных флюидов с ярко выраженными признаками образования паровой фазы.

В работе проиллюстрировано влияние качества глубинных проб на результаты исследований фазового поведения парафинов и асфальтенов пластовой нефти. Сравнивались результаты исследований условно представительной пробы пластовой нефти и глубинных проб, отобранных в условиях многофазного потока, что повлекло за собой попадание в камеры пробоотборников различного объема свободного газа, пластовой воды и твердой фазы асфальтенов, смол и парафинов. По каждой пробе был проведен комплекс PVT-исследований согласно ОСТ 153-39.2-048-2003 и Стандарта ПАО «Газпромнефть» М-01.01.03.04-02 «Лабораторные исследований проб пластовых флюидов» (исследование PV-соотношений, однократное разгазирование, определение вязкости и плотности) и исследование фазового поведения парафинов и асфальтенов методами акустического резонанса (регистрация момента фазового перехода), микроскопии высокого давления (определение количества и геометрических размеров частиц твердой фазы), гравиметрическим и фильтрационным методами (определение группового состава твердой фазы). Для подготовки глубинных проб нефти с газовыми шапками в камерах была проведена процедура выпуска свободного газа до текущего давления насыщения нефти газом. По результатам анализов выявлено, что процедура выпуска свободного газа влияет на PVT-характеристики проб незначительно: расхождение основных экспериментально определенных параметров не превышало допуски ОСТ 153-39.2-048-2003, однако такие пробы непригодны к исследованиям фазового поведения парафинов и асфальтенов, поскольку расхождения различных параметров (содержание асфальтенов, смол и парафинов, температура насыщения нефти парафином, давление насыщения нефти асфальтеном и пр.) достигает 70%. Следует учитывать, что, в случае необходимости подобного рода исследований, геологической службой недропользователя совместно со специалистами Научно-технических центров, а также подрядных организаций, осуществляющих как отбор проб, так и лабораторные исследования, необходимо особенно тщательно прорабатывать план работ на скважине и контролировать процедуры подготовки скважины и отбора проб.

The overview and analysis of technical, regulatory and procedural, administrative and business aspects of current situation in the field of downhole sampling in the Russian Federation is presented. The author's viewpoint on the physical and chemical factors of the samples quality is presented, concept and development trends of systematic approach to quality control of downhole sampling are proposed.

Аннотация. Настоящей работой авторы продолжают цикл статей, посвященных методическим, технологическим, метрологическим и иным аспектам проведения и обработки результатов исследований PVT-соотношений пластовых нефтей. Рассмотрена математическая природа Y-фактора и гипотезы по применению методов математического анализа для оценки давления насыщения флюидов различной природы.

SummaryFull-field flow simulators use a variety of cell geometries, rang-ing from simple rectangles to complex corner-point systems. One of the benefits of corner-point cells is the ease with which we may represent faulted reservoirs. Each face of a cell may be juxtaposed to two or more cells, depending on the fault throw and the lateral displacements of adjacent cells. Conventional finite-dif-ference approaches routinely include the flux between these cells as "nonneighbor" connections. Other examples of nonneighbor or nonstandard connections occur at the boundary of local grid refinement (LGR) or local grid coarsening (LGC) regions where two computational grids come into juxtaposition. In each of these instances, the velocity across the nonstandard faces of a cell will be unevenly distributed according to the nonneighbor fluxes. In contrast, the standard streamline velocity interpolation model (Pol-lock's scheme) used within a cell assumes that the flux is evenly dis...

Analisis Pressure Build Up pada sumur “ASR-06” dilakukan untuk mengetahui karakteristik fluida di reservoir. Analisis ini dilakukan untuk mengetahui tekanan yang berada pada reservoir. Hasil uji tes  kemudian dianalisis menggunakan pressure derivative dan horner plot. Dari hasil analisis ini dapat diketahui bahwa sumur “ASR-06” mengalami penurunan kompresibilitas fluida sehingga menyebabkan terjadinya penyimpangan pada pembacaaan kurva pressure derivative pada early time region. Hal ini dapat terjadi dikarenakan adanya fluida gas dan fluida liquid yang mengalir secara bersamaan. kedalam tubing dan mengakibatkan berkurangnya ruangan untuk fluida gas untuk mengalir didalam ruang tertutup. Fenomena changing wellbore storage akan mengakibatkan anomali pembacaan tekanan lubang sumur menjadi lebih tinggi daripada tekanan formasi pada waktu awal. Pada hasil pembacaan pressure build-up dengan metode pressure derivative didapatkan nilai skin dan permebabilitas yaitu 2.15 mD dan 4.75. Pada me...

The heterolithic thin-bedded sand and shale are very commonly associated reservoirs column in shallow water clastic depositional environment in Malaysia Basin. The complexity in reservoirs characterization of heterolithic thin-bedded sand often leads to underestimating the potential contribution of these types of the reservoir for development and exploration targets. The naturally laminated of heterolithic thin-bedded sand make it more difficult in building the realistic 3D geological model and has an impact on volumetric calculation and reserve estimation. This study is applied in the development phase by introducing Log resolution enhancement methods in laminated thin-bedded sand characterization to quantify the reservoir potential with high-resolution 3D modelling methods. The quantification of sand and shale in thin bedded analysis using core data and image logs, then transform into lithofacies classification from sand and shale volume cutoff. The distribution and computation of lithofacies and reservoir properties build into a 3D model is obtained from a geological depositional environment analog at field-scale of a conventional setting. The results indicated high-resolution 3D geological modelling successfully preserved the characterization of thin-bedded sand and shale; and revealed an excellent correlation with the image log. The presence of inter-bedded sand and shale of reservoir column in the 3D geological model provides the quantification of thin-bedded sand contribution and potential realistic volumetric estimation for the entire reservoir interval. The thin-bedded reservoir characterization and high-resolution 3D modelling technique successfully address the existent of heterolithic reservoir facies previously simplified.