Seismic, geologic, geomechanics, and dynamic constraints in flow models of unconventional fractured reservoirs: Example from a south Texas field

2019 ◽  
Vol 38 (2) ◽  
pp. 116-122 ◽  
Author(s):  
Reinaldo J. Michelena ◽  
James R. Gilman ◽  
Christopher K. Zahm
Keyword(s):  
Multiple Scales ◽  
Fractured Reservoirs ◽  
Flow Simulation ◽  
South Texas ◽  
Naturally Fractured Reservoirs ◽  
Flow Models ◽  
Dynamic Constraints ◽  
Well Spacing ◽  
Orientation Statistics ◽  
The Impact

We present a workflow to build permeability models for flow simulation in unconventional naturally fractured reservoirs constrained by 3D seismic, geologic data and concepts, geomechanics observations, and dynamic data. Joints and faults are modeled separately to account for their differences in scale and flow properties. Seismic-derived orientation statistics are compared against orientations from outcrops and microseismic data to assess their validity and consistency across multiple scales. We show the impact of natural fractures and stress orientation in the flow and variability of the pressure field around producing wells in an unconventional reservoir from south Texas. Such variability can have a significant impact on well interference and optimal well spacing.

Stabilized Water-Cut in Carbonate Naturally-Fractured Reservoirs With Bottom Water With an Implication in Well Spacing Design for Recovery Optimization

2018 ◽  
Author(s):  
Samir Prasun ◽  
A. K. Wojtanowicz
Keyword(s):  
Final Stage ◽  
Bottom Water ◽  
Fractured Reservoirs ◽  
Capillary Forces ◽  
Naturally Fractured Reservoirs ◽  
Oil Displacement ◽  
Well Spacing ◽  
Constant Rate ◽  
Water Coning ◽  
Water Cut

Maximum stabilized water-cut (WC), also known as ultimate water-cut in a reservoir with bottom-water coning, provides important information to decide if reservoir development is economical. To date, theory and determination of stabilized water-cut consider only single-permeability systems so there is a need to extend this concept to Naturally Fractured Reservoirs (NFRs) in carbonate rocks — known for severe bottom water invasion. This work provides insight of the water coning mechanism in NFR and proposes an analytical method for computing stabilized water-cut and relating to well-spacing design. Simulated experiments on a variety of bottom-water hydrophobic NFRs have been designed, conducted, and analyzed using dual-porosity/dual-permeability (DPDP) commercial software. They show a pattern of water cut development in NFR comprising the early water breakthrough and very rapid increase followed by water cut-stabilization stage, and the final stage with progressive water-cut. The initial steply increase of water-cut corresponds to water invading the fractures. The stabilized WC production stage occurs when oil is displaced at a constant rate from matrix to the water-producing fractures. During this stage water invades matrix at small values of capillary forces so they do not oppose water invasion. In contrast, during the final stage (with progressing water cut) the capillary forces grow significantly so they effectively oppose water invasion resulting in progressive water cut. A simple analytical model explains the constant rate of oil displacement by considering the driving effect of gravity and viscous forces at a very small value of capillary pressure. The constant oil displacement effect is confirmed with a designed series of simulation experiments for a variety of bottom-water NFRs. Statistical analysis of the results correlates the duration of the stabilized WC stage with production rate and well-spacing and provides the basis for optimizing the recovery. Results show that stabilized water-cut stage does not significantly contribute to recovery, so the stage needs to be avoided. Proposed is a new method for finding the optimum well spacing that eliminates the stabilized WC stage while maximizing recovery. The method is demonstrated for the base-case NFR.

scholarly journals Predictive Modelling of Naturally Fractured Reservoirs Using Geomechanics and Flow Simulation

GeoArabia ◽  
2001 ◽  
Vol 6 (1) ◽  
pp. 27-42
Author(s):  
Stephen J. Bourne ◽  
Lex Rijkels ◽  
Ben J. Stephenson ◽  
Emanuel J.M. Willemse
Keyword(s):  
Fractured Reservoirs ◽  
Flow Simulation ◽  
Naturally Fractured Reservoirs ◽  
Natural Fracture ◽  
Production Data ◽  
Well Test ◽  
Fracture Networks ◽  
Field Scale ◽  
Fracture Permeability ◽  
Naturally Fractured

ABSTRACT To optimise recovery in naturally fractured reservoirs, the field-scale distribution of fracture properties must be understood and quantified. We present a method to systematically predict the spatial distribution of natural fractures related to faulting and their effect on flow simulations. This approach yields field-scale models for the geometry and permeability of connected fracture networks. These are calibrated by geological, well test and field production data to constrain the distributions of fractures within the inter-well space. First, we calculate the stress distribution at the time of fracturing using the present-day structural reservoir geometry. This calculation is based on a geomechanical model of rock deformation that represents faults as frictionless surfaces within an isotropic homogeneous linear elastic medium. Second, the calculated stress field is used to govern the simulated growth of fracture networks. Finally, the fractures are upscaled dynamically by simulating flow through the discrete fracture network per grid block, enabling field-scale multi-phase reservoir simulation. Uncertainties associated with these predictions are considerably reduced as the model is constrained and validated by seismic, borehole, well test and production data. This approach is able to predict physically and geologically realistic fracture networks. Its successful application to outcrops and reservoirs demonstrates that there is a high degree of predictability in the properties of natural fracture networks. In cases of limited data, field-wide heterogeneity in fracture permeability can be modelled without the need for field-wide well coverage.

Predictive modelling of naturally fractured reservoirs using geomechanics and flow simulation

2000 ◽  
Author(s):  
Stephen J. Bourne ◽  
Franz Brauckmann ◽  
Lex Rijkels ◽  
Ben J. Stephenson ◽  
Alex Weber ◽  
...  
Keyword(s):  
Fractured Reservoirs ◽  
Flow Simulation ◽  
Predictive Modelling ◽  
Naturally Fractured Reservoirs ◽  
Naturally Fractured

Stabilized Water-Cut in Carbonate Naturally Fractured Reservoirs With Bottom Water With an Implication in Well Spacing Design for Recovery Optimization

2020 ◽  
Vol 142 (3) ◽  
Author(s):  
Samir Prasun ◽  
Andrew K. Wojtanowicz
Keyword(s):  
Final Stage ◽  
Bottom Water ◽  
Fractured Reservoirs ◽  
Capillary Forces ◽  
Naturally Fractured Reservoirs ◽  
Oil Displacement ◽  
Well Spacing ◽  
Constant Rate ◽  
Water Coning ◽  
Water Cut

Abstract Maximum stabilized water-cut (WC), also known as ultimate water-cut in a reservoir with bottom-water coning, provides important information to decide if reservoir development is economical. To date, theory and determination of stabilized water-cut consider only single-permeability systems so there is a need to extend this concept to naturally fractured reservoirs (NFRs) in carbonate rocks—known for severe bottom-water invasion. This work provides insight of the water coning mechanism in NFR and proposes an analytical method for computing stabilized water-cut and relating to well-spacing design. Simulated experiments on a variety of bottom-water hydrophobic NFRs have been designed, conducted, and analyzed using the dual-porosity/dual-permeability (DPDP) commercial software. They show a pattern of water-cut development in NFR comprising the early water breakthrough and very rapid increase followed by water-cut stabilization stage, and the final stage with progressive water-cut. The initial steply increase of water-cut corresponds to water invading the fractures. The stabilized WC production stage occurs when oil is displaced at a constant rate from matrix to the water-producing fractures. During this stage, water invades matrix at small values of capillary forces so they do not oppose water invasion. In contrast, during the final stage (with progressing water cut), the capillary forces grow significantly so they effectively oppose water invasion resulting in progressive water cut. A simple analytical model explains the constant rate of oil displacement by considering the driving effect of gravity and viscous forces at a very small value of capillary pressure. The constant oil displacement effect is confirmed with a designed series of simulation experiments for a variety of bottom-water NFRs. Statistical analysis of the results correlates the duration of the stabilized WC stage with production rate and well-spacing and provides the basis for optimizing the recovery. Results show that stabilized water-cut stage does not significantly contribute to recovery, so the stage needs to be avoided. Proposed is a new method for finding the optimum well spacing that eliminates the stabilized WC stage while maximizing recovery. The method is demonstrated for the base-case NFR.

scholarly journals Using Low Salinity Waterflooding to Improve Oil Recovery in Naturally Fractured Reservoirs

2020 ◽  
Vol 10 (12) ◽  
pp. 4211
Author(s):  
Faisal Awad Aljuboori ◽  
Jang Hyun Lee ◽  
Khaled A. Elraies ◽  
Karl D. Stephen
Keyword(s):  
Oil Recovery ◽  
Low Cost ◽  
Fractured Reservoirs ◽  
Cost Effective ◽  
Weighting Factor ◽  
Naturally Fractured Reservoirs ◽  
Low Salinity ◽  
Naturally Fractured ◽  
Low Salinity Waterflooding ◽  
The Impact

Low salinity waterflooding is an effective technique to accelerate and boost oil recovery. The impact of this technique has been investigated widely in laboratories for various scales and rock typing, most of which have demonstrated a potential improvement in oil recovery. This improvement has been attributed to several chemical and physical interactions that led to a change in the wettability to become more water-wet, as well as a reduction in the residual oil saturation. Meanwhile, it is rare to find a discussion in the literature about the efficiency of low salinity flooding in naturally fractured reservoirs. Therefore, in this work, we investigate the potential advantages of this method in fractured reservoirs using numerical simulations. A new approach to estimate the weighting factor using a tracer model has been proposed to determine the brine salinity and, hence, its properties in the mixing region. We have also used the relative permeability curves as a proxy for any physical and chemical mechanisms which are not represented explicitly in the model. The simulation outcomes highlighted the advantage of low salinity waterflooding in fractured reservoirs. An increment in oil recovery by 10.7% to 13% of Stock Tank Oil Initially In Place (STOIIP) was obtained using the dual- and single-porosity model, respectively. Therefore, the low salinity waterflooding technique represents a promising low-cost, effective method in fractured reservoirs.

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