EXPERIMENTAL AND NUMERICAL SIMULATION OF HOT WATER INJECTION TO DEEP CARBONATE RESERVOIR

2019 ◽  
Author(s):  
Aysylu Askarova
Keyword(s):  
Numerical Simulation ◽  
Water Injection ◽  
Carbonate Reservoir ◽  
Hot Water

A New Approach to Simulation of Wax Precipitation During Cold Water Injection in Carbonate Reservoir of Kharyaga Oilfield

2021 ◽  
Author(s):  
Yuri Mikhailovich Trushin ◽  
Anton Sergeevich Aleshchenko ◽  
Oleg Nikolaevich Zoshchenko ◽  
Mark Suleimanovich Arsamakov ◽  
Ivan Vasilevich Tkachev ◽  
...  
Keyword(s):  
Cold Water ◽  
Water Injection ◽  
Carbonate Reservoir ◽  
Hot Water ◽  
Reservoir Rock ◽  
Laboratory Studies ◽  
Wax Deposition ◽  
Field Development ◽  
Sector Model ◽  
The Impact

Abstract The paper describes a methodology for assessing the impact of wax deposition in reservoir oil during cold water injection into heterogeneous carbonate reservoir D3-III of the Kharyaga field. The main goal is to determine the optimal amount of hot water that must be injected before switching to cold water without affecting the field development. The paper presents the results of laboratory studies to determine the thermophysical properties of oil, samples of net reservoir and non-reservoir rock, as well as the results of laboratory studies to determine the conditions and nature of wax deposition in oil when the temperature and pressure conditions change. Calculations were carried out to describe the physical model of oil displacement by water of various temperatures. A series of synthetic sector model runs was performed, which includes the average properties of the selected reservoir and the results of laboratory studies in order to determine the effect of cold water injection on the development performance.

Numerical simulation of water injection into layered fractured carbonate reservoir analogs

AAPG Bulletin ◽  
2006 ◽  
Vol 90 (10) ◽  
pp. 1473-1493 ◽  
Author(s):  
Mandefro Belayneh ◽  
Sebastian Geiger ◽  
Stephan K. Matthäi
Keyword(s):  
Numerical Simulation ◽  
Water Injection ◽  
Carbonate Reservoir ◽  
Fractured Carbonate

Integrated Study of a Fractured Middle East Reservoir With Stratiform Super-K Intervals-Part 2:Upscaling and Dual-Media Simulation

2002 ◽  
Vol 5 (01) ◽  
pp. 24-32 ◽  
Author(s):  
L. Cosentino ◽  
Y. Coury ◽  
J.M. Daniel ◽  
E. Manceau ◽  
C. Ravenne ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Middle East ◽  
Reservoir Simulation ◽  
Water Injection ◽  
Companion Paper ◽  
Carbonate Reservoir ◽  
Geostatistical Model ◽  
Reservoir Heterogeneity ◽  
The Impact

Summary The paper describes the upscaling and reservoir simulation of a giant Middle East oil field, the geological modeling of which is described in a companion paper.1 The main objective of the study was the simulation of the irregular water advance observed in some parts of the field as a consequence of peripheral water injection. Three scales of heterogeneity were identified in the characterization phase: the matrix, the stratiform Super-K intervals, and the fractures. To accommodate the different hydraulic properties of each heterogeneity system, a dual-media approach (dual porosity and dual permeability) was used. The assignment of the effective properties to the simulation grids (matrix and fracture grids) was performed independently for the three heterogeneity systems. In particular, the geostatistical facies model was upscaled with algebraic methods, while the stratiform Super-K layers and fracture properties were reproduced explicitly at the simulation gridblock scale through an original upscaling procedure. The history match was achieved in a short time by a small variation of the fractal dimension of the fracture distribution and without resorting to any local modification. Simulation results showed that the fracture system was the controlling factor in terms of water advance and breakthrough, while the impact of the stratiform Super-K layers proved to be of second order. In a later stage, the model was used to run production forecasts under different exploitation scenarios. The conclusions of this study indicate that for such porous and fractured reservoirs with stratiform Super-K occurrences, a detailed characterization of all the heterogeneity systems, coupled with a dual-media formulation, is necessary for accurate reservoir simulation and effective reservoir management. Introduction Heterogeneities are always present, to some degree, in natural petroleum reservoirs.2 Their impact can be very important in the overall dynamic behavior of the reservoirs, especially when secondary recovery projects are active (e.g., water or gas injection). In the Middle East, many oil reservoirs are currently experiencing unexpected production performance, especially early water breakthrough (BT), which usually starts soon after the implementation of waterflooding projects. In most studies, such unexpected behavior is generically related to the presence of reservoir heterogeneity in the form of some high-permeability conduits that link the injector and producer wells. Note that while such simplified understanding can be sufficient for a history-matching exercise, a much better description of the reservoir heterogeneity is required, in terms of type and distribution, when the simulation model is used in forecasting mode. This project concentrated on the geological description, upscaling, and numerical simulation of a giant Middle East carbonate reservoir, which experienced early water BT in some parts of the field. Because it was felt that reservoir heterogeneity was the driving factor behind this unexpected behavior, most of the effort was devoted to the description and simulation of such heterogeneity. The geological characterization of the reservoir is described in a companion paper.1 Three main heterogeneity systems were identified:The matrix. This consists of porous and permeable (up to 200 md) limestones and dolomites. A rock-type classification system was established by means of a multivariate statistical algorithm. Vertical and horizontal proportion curves were generated within a sequence stratigraphy framework, which showed strong nonstationary behavior. Eventually, a 3D facies geostatistical model was generated. Petrophysical properties were assigned to the fine-scale grid through an original inversion algorithm based on flowmeter data.3The stratiform Super-K intervals. These are thin, highly permeable layers with conductivity in excess of 500 B/D/ft. Their permeability is typically on the order of 1 to 5 darcies. Such intervals are defined through the analysis of the available flowmeters, and they have been included in the geostatistical model using a plurigaussian algorithm. A strong relationship between stratigraphic position and stratiform Super-K intervals was demonstrated. The extension, the shape, and the continuity of these bodies are largely unknown and are key factors of the characterization phases.The fractures. The presence of fractures has been inferred through the analysis of data from seismic interpretation, curvature analysis, and wellbore logs. Fractures do cluster in swarms that can be represented as heavily fractured lineaments (called fracture in the following sections). All the available data concerning these fracture swarms were integrated in a stochastic fault and fracture model, and alternative images were generated through a fractal approach. It should be stressed that the presence of significant fracture patterns has been proposed for the first time in this study because reservoir performances historically have been related mainly to matrix and Super-K characteristics and distribution.4,5 In the next sections, we describe the impact of these reservoir heterogeneities on the field behavior and the implementation of the available geological characterization in the simulation model. Problem Statement The field under study is a giant carbonate reservoir that has been on stream for almost 30 years. The reservoir was producing under fluid expansion and weak aquifer drive until 1995, when a waterflooding project started. Fig. 1 shows a map of the reservoir structure. Note that the field is part of a much larger oil accumulation that extends to the south and to the north; therefore, these limits do not correspond to real reservoir boundaries. The inner window shows the area retained for numerical simulation (pilot area). The main problem of the field under study is early water BT, especially in some wells located in the western flank. Such behavior has been observed in recent years, after the start of the water injection project, while no significant water production had been measured before that date.

scholarly journals Numerical Simulation and Engineering Application of Coalbed Water Injection

2019 ◽  
Vol 2019 ◽  
pp. 1-12 ◽  
Author(s):  
Yijie Shi ◽  
Pengfei Wang ◽  
Ronghua Liu ◽  
Xuanhao Tan ◽  
Wen Zhang
Keyword(s):  
Numerical Simulation ◽  
Process Parameters ◽  
Water Injection ◽  
Engineering Application ◽  
Working Environment ◽  
Engineering Practice ◽  
Characteristic Parameters ◽  
Injection Process ◽  
Working Face ◽  
Dust Reduction

Coalbed water injection is the most basic and effective dust-proof technology in the coal mining face. To understand the influence of coalbed water injection process parameters and coalbed characteristic parameters on coal wetting radius, this paper uses Fluent computational fluid dynamics software to systematically study the seepage process of coalbed water injection under different process parameters and coalbed characteristic parameters, calculation results of which are applied to engineering practice. The results show that the numerical simulation can help to predict the wetness range of coalbed water injection, and the results can provide guidance for the onsite design of coalbed water injection process parameters. The effect of dust reduction applied to onsite coalbed water injection is significant, with the average dust reduction rates during coal cutting and support moving being 67.85% and 46.07%, respectively, which effectively reduces the dust concentration on the working face and improves the working environment.

scholarly journals Injection-production optimization of carbonate reservoir based on an inter-well connectivity model

2021 ◽  
pp. 014459872199465
Author(s):  
Yuhui Zhou ◽  
Sheng Lei ◽  
Xuebiao Du ◽  
Shichang Ju ◽  
Wei Li
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Field Application ◽  
Carbonate Reservoir ◽  
Production Optimization ◽  
Oil Field ◽  
Carbonate Reservoirs ◽  
Utilization Rate ◽  
Production Volume ◽  
Connectivity Model

Carbonate reservoirs are highly heterogeneous. During waterflooding stage, the channeling phenomenon of displacing fluid in high-permeability layers easily leads to early water breakthrough and high water-cut with low recovery rate. To quantitatively characterize the inter-well connectivity parameters (including conductivity and connected volume), we developed an inter-well connectivity model based on the principle of inter-well connectivity and the geological data and development performance of carbonate reservoirs. Thus, the planar water injection allocation factors and water injection utilization rate of different layers can be obtained. In addition, when the proposed model is integrated with automatic history matching method and production optimization algorithm, the real-time oil and water production can be optimized and predicted. Field application demonstrates that adjusting injection parameters based on the model outputs results in a 1.5% increase in annual oil production, which offers significant guidance for the efficient development of similar oil reservoirs. In this study, the connectivity method was applied to multi-layer real reservoirs for the first time, and the injection and production volume of injection-production wells were repeatedly updated based on multiple iterations of water injection efficiency. The correctness of the method was verified by conceptual calculations and then applied to real reservoirs. So that the oil field can increase production in a short time, and has good application value.

scholarly journals A Numerical Method for Computing Recovery of Oil By Hot Water Injection in a Radial System

1965 ◽  
Vol 5 (02) ◽  
pp. 131-140 ◽  
Author(s):  
K.P. Fournier
Keyword(s):  
Thermal Expansion ◽  
Oil Recovery ◽  
Viscosity Ratio ◽  
Water Injection ◽  
Injection Rate ◽  
Heat Losses ◽  
Hot Water ◽  
Radial System ◽  
System Equation ◽  
Finite Difference Equations

Abstract This report describes work on the problem of predicting oil recovery from a reservoir into which water is injected at a temperature higher than the reservoir temperature, taking into account effects of viscosity-ratio reduction, heat loss and thermal expansion. It includes the derivation of the equations involved, the finite difference equations used to solve the partial differential equation which models the system, and the results obtained using the IBM 1620 and 7090–1401 computers. Figures and tables show present results of this study of recovery as a function of reservoir thickness and injection rate. For a possible reservoir hot water flood in which 1,000 BWPD at 250F are injected, an additional 5 per cent recovery of oil in place in a swept 1,000-ft-radius reservoir is predicted after injection of one pore volume of water. INTRODUCTION The problem of predicting oil recovery from the injection of hot water has been discussed by several researchers.1–6,19 In no case has the problem of predicting heat losses been rigorously incorporated into the recovery and displacement calculation problem. Willman et al. describe an approximate method of such treatment.1 The calculation of heat losses in a reservoir and the corresponding temperature distribution while injecting a hot fluid has been attempted by several authors.7,8 In this report a method is presented to numerically predict the oil displacement by hot water in a radial system, taking into account the heat losses to adjacent strata, changes in viscosity ratio with temperature and the thermal-expansion effect for both oil and water. DERIVATION OF BASIC EQUATIONS We start with the familiar Buckley-Leverett9 equation for a radial system:*Equation 1 This can be written in the formEquation 2 This is sometimes referred to as the Lagrangian form of the displacement equation.

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