Validation of Near-Wellbore Fracture-Network Models With MDT
- F.M. Verga (Politecnico di Torino) | G. Giglio (Politecnico di Torino) | F. Masserano (ENI-Agip) | L. Ruvo (ENI-Agip)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 2002
- Document Type
- Journal Paper
- 116 - 125
- 2002. Society of Petroleum Engineers
- 5.5 Reservoir Simulation, 1.8 Formation Damage, 5.1.5 Geologic Modeling, 1.14 Casing and Cementing, 5.6.3 Pressure Transient Testing, 5.8.6 Naturally Fractured Reservoir, 1.10 Drilling Equipment, 1.11 Drilling Fluids and Materials, 5.1.7 Seismic Processing and Interpretation, 5.8.7 Carbonate Reservoir, 5.6.1 Open hole/cased hole log analysis, 1.12.2 Logging While Drilling, 1.6 Drilling Operations, 1.6.9 Coring, Fishing, 5.5.11 Formation Testing (e.g., Wireline, LWD), 5.1.2 Faults and Fracture Characterisation, 4.3.4 Scale, 3 Production and Well Operations, 5.1 Reservoir Characterisation, 5.1.1 Exploration, Development, Structural Geology, 5.6.4 Drillstem/Well Testing, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.6.3 Deterministic Methods
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A new approach was attempted to validate the reconstructed internal geometry of a fractured reservoir by reproducing the reservoir dynamic behavior monitored during modular dynamic tests (MDTs). The description of the reservoir fracture network was achieved by integrating relevant data that could be collected from wireline logs, conventional cores, small drilling-mud-loss analysis, and field-scale observations from outcrop analog inspection. Fracture types, properties, and distributions were thus defined, and a static model of the fractured reservoir was generated stochastically. The dynamic behavior of the fractured system was reproduced by a finite-element flow model. Consistency was required between the observed and simulated pressure data to ensure that the reservoir geometry was modeled adequately. Analysis of the model response as a function of the assigned fracture parameters and comparison between the observed and simulated dynamic behavior allowed achievement of a satisfactory description of the reservoir effective fracture network.
This paper presents the procedure applied to generate and validate the model of near-wellbore regions for an oil-bearing fractured reservoir. The described procedure is considered a strategic part of a newly elaborated methodology aimed at better characterizing classical dual-porosity systems.1 In fact, there is a common feeling that improved description and understanding of fractured reservoirs is needed, as is apparent by analogous integrated procedures recently suggested or outlined by other authors.2-6
The developed methodology is mainly based on the definition of a certain number of structural segments and/or near-wellbore regions inside the reservoir. Fracture distributions are generated stochastically within each region, according to all the available data, to reproduce the rock-fracture network. The dynamic behavior of the fracture-network model is then simulated and compared to the observed production-test responses until a satisfactory match is achieved by the appropriate tuning of the model parameters. Once the dynamic model has been calibrated, the equivalent fracture and matrix parameters (i.e., fracture porosity, fracture permeability, matrix block size, and sigma factor) are obtained and extrapolated to the whole reservoir by adoption of appropriate drivers (such as lithology, stress field, and curvature), and they are selected according to their respective significance for the reservoir under study.3,5
In particular, the case study discussed in this paper is focused on the generation and calibration of a fracture-network model that reproduces the reservoir region surrounding the well at which all the data have been collected.
The fracture pattern and aperture were statistically defined by the integration of data obtained from image-log recordings, conventional core analyses, drilling-mud-loss interpretations, and observations on outcrop analogs. Only the properties of the main fractures intercepted by the wellbore were deterministically assigned to the model. Image logs and cores from another nearby well were also considered to verify the consistency on the fracturepattern characterization. Upscaling of the fracture distributions observed at the wellbore and at core scale was required to generate a representative model of the formation.
A finite-element model of the fracture network was then generated to properly describe the fluid flow in the reservoir, whereas the flow in the matrix was simulated according to a generic matrix-block approach.6,7
Simulations of the model dynamic behavior were performed to reproduce the pressure response recorded during the MDTs. Comparison between simulation results and measured pressure data allowed verification of the model consistency and calibration of the fracture intensity and permeability.3,6
The investigated reservoir is an oil-bearing, fractured formation mainly made up of massive, unstratified, tight calcareous dolomite (carbonate platform). The field is an elongated, strongly faulted, northwest/southeast-trending anticline located above a northeast-verging thrust zone, which gently dips toward the southwest. The gross reservoir thickness at the well is approximately 400 m.
The oil is strongly undersaturated at the initial reservoir conditions, and the oil density is 32°API.
According to the 3D seismic interpretation, two dominant fault sets can be observed. The main set is oriented northwest/southeast, whereas the orientation of the second set is slightly different (north-northwest/south-southeast). A minor set, oriented northeast/ southwest and constituted by small faults rarely exceeding 1 km in length, is also present.
The reservoir formations crop out approximately 10 to 15 km south of the field: several structural studies, carried out both at macroscopic scale (geological maps and aerial photographs) and at mesoscopic scale (outcrop), are available for this analogue. According to the geological maps, two fault sets are present, oriented northwest/southeast and northeast/southwest, respectively; the former is more intense and shows a little dispersion in the strike distribution. Aerial photos show the existence of some north-northeast/ south-southwest-trending lineations, younger than the previously described faults. The length of these lineations ranges between 0.5 and 1 km. Outcrop data show three main fracture sets (oriented north-northeast/south-southwest, west-northwest/east-southeast, and northeast/southwest, respectively) more ancient than the outcropping faults.
Based on these data, the tectonic history of the area has been subdivided into three main phases:
A tensile phase - the carbonate platform was dismembered, and the previously mentioned north-northeast/south-southwest, west-northwest/east-southeast, and northeast/southwest fracture sets were generated.
A transpressive phase - the northwest/southeast and northeast/ southwest faults set were created; significant thrusting and backthrusting movements also occurred.
A new tensile phase - it is still active and contributes to the reactivation of the old fracture sets (northwest/southeast, northeast/ southwest, and north-northeast/south-southwest-oriented) and to the generation of the regional scale north-northeast/south-southwest- oriented lineations.
The status of the present-day stress field also has been studied; the breakout analysis on vertical and deviated wells shows that smin is southwest/northeast-oriented (i.e., it is perpendicular to the direction of the main fracture sets), while smax acts along the vertical direction.
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