Determination of Reservoir Properties From Backpressure Tests With Applications to Reservoir Simulation

1976 ◽  
Vol 28 (05) ◽  
pp. 603-610
Author(s):  
R.Y.L. Chain ◽  
C.J. Mountford ◽  
R. Raghavan ◽  
G.W. Thomas
Keyword(s):  
Reservoir Simulation ◽  
Reservoir Properties

A Fast Gridding Method for Capturing Geological Complexity and Uncertainty

2021 ◽  
Author(s):  
Yifei Xu ◽  
Priyesh Srivastava ◽  
Xiao Ma ◽  
Karan Kaul ◽  
Hao Huang
Keyword(s):  
Efficient Method ◽  
Reservoir Simulation ◽  
History Matching ◽  
Mapping Method ◽  
Reservoir Properties ◽  
Structural Framework ◽  
Assisted History Matching ◽  
Grid Topology ◽  
Geological Complexity ◽  
Complex Channel

Abstract In this paper, we introduce an efficient method to generate reservoir simulation grids and modify the fault juxtaposition on the generated grids. Both processes are based on a mapping method to displace vertices of a grid to desired locations without changing the grid topology. In the gridding process, a grid that can capture stratigraphical complexity is first generated in an unfaulted space. The vertices of the grid are then displaced back to the original faulted space to become a reservoir simulation grid. The resulting reversely mapped grid has a mapping structure that allows fast and easy fault juxtaposition modification. This feature avoids the process of updating the structural framework and regenerating the reservoir properties, which may be time-consuming. To facilitate juxtaposition updates within an assisted history matching workflow, several parameterized fault throw adjustment methods are introduced. Grid examples are given for reservoirs with Y-faults, overturned bed, and complex channel-lobe systems.

The Advantages of Having Dedicated Downhole Gauges and Wellhead Meter: A Reservoir Management Perspective from a Massive Tight Gas Reservoir in the Remote Area

2021 ◽  
Author(s):  
Ricko Rizkiaputra ◽  
Satrio Goesmiyarso ◽  
Jufenilamora Nurak ◽  
Krishna Pratama Laya ◽  
Dimmas Ramadhan ◽  
...  
Keyword(s):  
Reservoir Simulation ◽  
Transient Analysis ◽  
Management Practice ◽  
Reservoir Management ◽  
Remote Area ◽  
Tight Gas ◽  
Reservoir Properties ◽  
Gas Reservoir ◽  
Tight Gas Reservoir ◽  
Interference Test

Abstract Even though the downhole gauges and wellhead meter (wet gas meter) have been invented decades ago, having them installed in every wells are still considered as a luxury for many companies. However, does this view still reasonable for a tight gas reservoir let alone located in a remote area? This study will describe the benefit of having both equipment for reservoir management practice in one of the biggest tight gas reservoirs in Indonesia. Generally, reservoir management is an iterative process that incorporates the analysis of reservoir characterization, development plan, implementation, and monitoring. There are many analyses from the reservoir management process that can be performed using above mentioned equipment. Several analyses have been performed, such as: (i) Interference Test and Pressure Transient Analysis (PTA) after well is completed; (ii) Evolution of connected volume since early production until present day using Dynamic Material Balance (DMB); (iii) Flow regime and reservoir properties using Rate Transient Analysis (RTA); and (iv) Reservoir simulation: regular model update and project opportunity identification. In this study, the above-mentioned analyses are performed in one of the massive tight gas reservoir in Indonesia that is located in the remote area. Having a complete reservoir surveillance tools such as downhole gauges and wellhead meter on each wells is beneficial for reservoir management practice. Precious subsurface data can be obtained anytime without having to wait for equipment mobilization to location. This is critical for managing tight gas reservoir which usually demands robust subsurface data to reduce its uncertainties. There are several findings based on the above mentioned analyses, such as: (i) The interference test indicates there is reservoir connectivity among the production wells; (ii) The PTA indicates that the reservoir has tight properties, although longer buildup/observation time is still needed to better understand the reservoir characteristics in wider scale; (iii) The DMB analysis can be performed even in daily basis to provide the insight on connected gas initial in place (GIIP) evolution through time, as in this case it still shows an increasing GIIP through time which is suspected due to the transient flow regime on the wells; (iv) The RTA can also be performed in similar fashion, if it is combine with other analyses, this analysis able to provide a multi-scale reservoir properties investigation from near wellbore to far field and flow period observation (boundary observation) through time, as in this case the reservoir properties is tight and flow is still in transient period; (v) It increases robustness of reservoir simulation update since it is supported by many analyses, as such, series of hopper can be confidently presented to management, as in this case a project of well stimulation (Acid Fracturing) has been performed successfully and opportunity of further field development plan can be identified. This paper shows that, for the tight reservoir in the remote location, having each well equipped with downhole gauges and dedicated wellhead meter is significantly increasing the robustness of reservoir management process. Thus, providing economic optimization for the managed asset. Regarding the capital that is invested at the beginning, it will simply pay out quickly, looking at the time and resources that need to be spent for having equipment on site.

Experience in Optimizing the Location and Parameters of Multistage Hydraulic Fractures for a Multilateral Well Based on Reservoir Simulation

2021 ◽  
Author(s):  
Vil Syrtlanov ◽  
Yury Golovatskiy ◽  
Konstantin Chistikov ◽  
Dmitriy Bormashov
Keyword(s):  
Hydraulic Fracturing ◽  
Reservoir Simulation ◽  
Optimal Placement ◽  
Hydraulic Fractures ◽  
Low Permeability ◽  
Advantages And Disadvantages ◽  
Modeling Methods ◽  
Multistage Hydraulic Fracturing ◽  
Determination Of Parameters

Abstract This work presents the approaches used for the optimal placement and determination of parameters of hydraulic fractures in horizontal and multilateral wells in a low-permeability reservoir using various methods, including 3D modeling. The results of the production rate of a multilateral dualwellbore well are analyzed after the actual hydraulic fracturing performed on the basis of calculations. The advantages and disadvantages of modeling methods are evaluated, recommendations are given to improve the reliability of calculations for models with hydraulic fracturing (HF)/ multistage hydraulic fracturing (MHF).

Sequentially Adapted Flow-Based PEBI Grids for Reservoir Simulation

SPE Journal ◽  
2006 ◽  
Vol 11 (03) ◽  
pp. 317-327 ◽  
Author(s):  
Martin Mlacnik ◽  
Louis J. Durlofsky ◽  
Zoltan E. Heinemann
Keyword(s):  
Reservoir Simulation ◽  
Large Body ◽  
Structural Features ◽  
Flow In Porous Media ◽  
Fine Scale ◽  
Reservoir Properties ◽  
Fine Grid ◽  
Grid Coarsening ◽  
Grid Optimization ◽  
High Level

Summary A technique for the sequential generation of perpendicular-bisectional (PEBI) grids adapted to flow information is presented and applied. The procedure includes a fine-scale flow solution, the generation of an initial streamline-isopotential grid, grid optimization, and upscaling. The grid optimization is accomplished through application of a hybrid procedure with gradient and Laplacian smoothing steps, while the upscaling is based on a global-local procedure that makes use of the global solution used in the grid-determination step. The overall procedure is successfully applied to a complex channelized reservoir model involving changing well conditions. The gridding and upscaling procedures presented here may also be suitable for use with other types of structured or unstructured grid systems. Introduction Modern geological and geostatistical tools provide highly detailed descriptions of the spatial variation of reservoir properties, resulting in fine-grid models consisting of 107 to 108 gridblocks. As a consequence of this high level of detail, these models cannot be used directly in numerical reservoir simulators, but need to be coarsened significantly. Coarsening requires the averaging of rock parameters from the fine scale to the coarse scale. This process is referred to as upscaling. For simulation of flow in porous media, the upscaling of permeability is of particular interest. A large body of literature exists on this topic; for a comprehensive review of existing techniques, see Durlofsky (2005). To preserve as much of the geological information of the fine grid as possible, the grid coarsening should not be performed uniformly, but with more refinement in areas that are expected to have large impact on the flow, including structural features, such as faults. Although grid-generation techniques based on purely static, nonflow-based considerations have been shown to produce reasonable results(Garcia et al. 1992), the application of flow-based grids is often preferable. Flow-based grids require the solution of some type of fine-scale problem. They are then constructed by exploiting the information obtained from streamlines (and possibly isopotentials) either directly or indirectly. Depending on the type of grid used, points will be defined as cell vertices or nodes, resulting in either a corner-point geometry or point-distributed grid. Several gridding techniques for reservoir simulation have been introduced along these lines, as we now discuss.

Estimation of the Location of the Boundary of a Petroleum Reservoir

1975 ◽  
Vol 15 (01) ◽  
pp. 19-38 ◽  
Author(s):  
Wen H. Chen ◽  
John H. Seinfeld
Keyword(s):  
History Matching ◽  
Single Phase ◽  
Steepest Descent ◽  
Petroleum Reservoir ◽  
Pressure Data ◽  
Reservoir Properties ◽  
Matching Problems ◽  
Reservoir Property ◽  
Boundary Location

Abstract This paper considers the problem of estimating the shape of a petroleum reservoir on the basis of pressure data from wells within the boundaries of pressure data from wells within the boundaries of the reservoir. It is assumed that the reservoir properties, such as permeability and porosity, are properties, such as permeability and porosity, are known but that the location of the boundary is unknown. Thus, this paper addresses a new class of history-matching problems in which the boundary position is the reservoir property to be estimated. position is the reservoir property to be estimated. The problem is formulated as an optimal-control problem (the location of the boundary being the problem (the location of the boundary being the control variable). Two iterative methods are derived for the determination of the boundary location that minimizes a functional, depending on the deviation between observed and predicted pressures at the wells. The steepest-descent pressures at the wells. The steepest-descent algorithm is illustrated in two sample problems:the estimation of the radius of a bounded circular reservoir with a centrally located well, andthe estimation of the shape of a two-dimensional, single-phase reservoir with a constant-pressure outer boundary. Introduction A problem of substantial economic importance is the determination of the size and shape of a reservoir. Seismic data serve to define early the probable area occupied by the reservoir; however, probable area occupied by the reservoir; however, a means of using initial well-pressure data to determine further the volume and shape of the reservoir would be valuable. On the basis of representing the pressure behavior in a single-phase bounded reservoir in terms of an eigenfunction expansion, Gavalas and Seinfeld have shown how the total pore volume of an arbitrarily shaped reservoir can be estimated from late transient pressure data at the completed wells. We consider pressure data at the completed wells. We consider here the related problem of the estimation of the shape (or the location of the boundary) of a reservoir from pressure data at an arbitrary number of wells. For reasons of economy, the time allowable for closing wells is limited. It is important, therefore, that any method developed for estimating the shape of a reservoir be applicable, in principle, from the time at which the wells are completed until the current time. Thus, the problem we consider here may be viewed as one in the general realm of history matching, but also one in which the boundary location is the property to be estimated rather than the reserved physical properties. The formulation in the present study assumes that everything is known about the reservoir except its boundary. In actual practice, the reverse is generally true. (By the time sufficient information is available regarding the spatial distribution of permeability and porosity, the boundaries may be fairly well known.) Nevertheless, relatively early in the life of a reservoir, when initial drillstem tests have served to identify an approximate distribution of properties, it may be of some importance to attempt to estimate the reservoir shape. Since knowledge of reservoir properties such as permeability and porosity is at properties such as permeability and porosity is at best a result of initial estimates from well testing, core data, etc., the assumption that these properties are known will, of course, lead only to an approximate reservoir boundary. As the physical properties are identified more accurately, the reservoir boundary can be more accurately estimated. It is the object of this paper to formulate in a general manner and develop and initially test computational algorithms for the class of history-matching problems in which the boundary is the unknown property.There are virtually no prior available results on the estimation of the location of the boundary of a region over which the dependent variable(s) is governed by partial differential equations. The method developed here, based on the variation of a functional on a variable region, is applicable to a system governed by a set of nonlinear partial differential equations with general boundary conditions. The derivation of necessary conditions for optimality and the development of two computational gradient algorithms for determination of the optimal boundary are presented in the Appendix. To illustrate the steepest-descent algorithm we present two computational examples using simulated reservoir data. SPEJ P. 19

scholarly journals Determination of Reservoir Properties of Gas Layers under Conditions of Creep of Rocks with the Kernel of Abel

2021 ◽  
Vol 133 (2) ◽  
pp. 31-33
Author(s):  
B. Z. Kazymov ◽  
◽  
Т. А. Samadov ◽  
S. H. Novruzova ◽  
E. V. Gadashova ◽  
...  
Keyword(s):  
Finite Difference ◽  
Finite Difference Method ◽  
Numerical Solution ◽  
Difference Method ◽  
Weighted Average ◽  
Reservoir Properties ◽  
Reservoir Volume ◽  
The Finite Difference Method ◽  
Over Time

The problem of determining reservoir properties (porosity, permeability) of gas layers developed in the depletion mode, whose rocks are subjected to creeping deformation with the Abel core, is considered. In order to determine the parameters that characterize reservoir properties of the reservoir, the authors indicate the possibility of using an appropriate numerical solution to the problem of determining the theoretical values of the reservoir volume-weighted average reservoir pressures over time, obtained using the finite difference method.

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