Case Study: Practical Approach on Modeling Low Intensity Natural Fractures Carbonate Reservoirs in Oman
Authors: Khamatdinov R. , Salter T. , Banerjee A. , Chughtai M. , Mascagnini C. , Kindi Z. , Al Ajmi I. A. , Al Rabaani M. 
Published: November 2024

Abstract
Dynamic modeling of naturally fractured reservoirs typically requires a dual porosity or dual porosity, dual permeability (dual porosity hereafter) modeling approach. However, for low density fractured reservoirs the utilization of such approach might be unnecessary and even inaccurate. Dynamic modeling of Natih Formation carbonates in Oman, investigated the most suitable modelling approach for reservoirs with matrix and fracture flow capacity.
The need for a dual porosity modeling approach required consideration of several data components: (1) review of the image log interpretation and expected fracture density in the reservoir, (2) pressure transient analysis and presence of dual media signature, (3) review of existing well production behaviour and their common and different production behavioural trends, (4) review of the permeability contrast in the field quantified from DFN modelling and petrophysical work. Based on the above information and considering S.J.Pirson hypothesis it was possible to define most suitable modeling approach for the Natih formation.
Image log interpretation review noted fractures to be most prevalent at the boundary of low and high density facies, suggesting that stratigraphic control was important. Relatively low fracture density in many other parts of the reservoir did not support overall communication dominated only by a fracture system.
Review of the pressure transient analysis data did not provide clear indication of a typical dual porosity signature.
Production history of Natih formation wells showed quite similar behaviour to each other in terms of rates and water cut changes in time. This is not aligned with heterogeneous well performance that is common in reservoirs with strong, areally heterogeneous natural fractures behaviour.
Review of the permeability contrast between upscaled DFN models and matrix permeability from petrophysical work does not indicate that S.J.Pirson criteria is met for dual porosity system.
All of the above supported utilization of the single porosity approach for dynamic modelling of the Natih formation reservoirs. Further simulation work showed good history matching results that further supported the chosen method.
Dual porosity is common modeling techniques for naturally fractured carbonate formations in the Middle East region. The approach described in this paper helps define criteria and draw application boundaries from observed data where this may or may not be suitable. This will favour fit-for-purpose dynamic models and save time and efforts during the simulation work.

Background on theory and common practices
For numerical simulation of fractured reservoirs, assessment of the impact of fractures on the dynamic state of reservoirs as a system becomes very important. To further understand this impact its essential to know to what degree fractures make an impact based on static parameters.
Reservoir engineers and geologists widely use Nelson's classification (1), that summarizes impact of fractures on porosity and permeability (Figure 1). Type 1 reservoirs refer to fractured reservoirs where fractures totally control porosity and permeability, for example, fractured granitic basements. Type 2 and 3 are reservoirs, where fractures are mainly responsible for the permeability (fluids transport) and hence controls its dynamics. Type 2 and 3 forms majority of fractured formations in the Middle East. In such reservoirs storage is controlled by the rock matrix, while flow is dominated by fractures. Type 3 are reservoirs where fractures assist matrix permeability and do not dominate the fluid flow. Type IV are reservoirs where fractures rather act as flow baffle instead of enhancing permeability, affecting reservoir continuity, and creating flow anisotropy.
Natih E reservoir discussed in this paper falls under type 3.
A dual porosity or dual permeability approach is applied in simulation when fractures form a connected, permeable network and have a significant impact on flow behaviour. However, if the impact of fractures on storage and flow is small, fractures can be thought as merely enhancing the overall rock permeability. If that is the case, then a conventional single medium model is sufficient to capture the dynamics of flow. It should be noted that application of discrete fracture models at a field scale might not always be practical, mainly due to limited information available characterizing the fracture network and more importantly CPU time of such simulations becomes prohibitive.
For ascertaining whether a single or dual medium approach to dynamic modelling is most suited, the indicators below should be considered:
Well Testing Data : Well test data needs to be evaluated for assessing well productivity. If the actual well permeability-thickness product (e.g. K × h) is higher than the permeability-thickness described by matrix properties alone, it is strong evidence for the additional impact of fracture flow. The term ‘flow capacity index’ (FCI) quantifies that impact.
FCI = kh well /kh matrix
Pressure transient analysis can often throw insights on strength of fracture behaviour. A linear flow regime would indicate effect of a single dominant fracture or may also contain distinct pressure responses from media of variable permeability. Often, these measurements are referred to as dual-porosity response. Test data in this case study were analysed and presented in subsequent sections.
Production behaviour : well production data might indicate contribution level of fractures in fluid flow. Typical questions such as ones below need to be answered:
Indicators from static description : S.J Pirson (2) put together the first dual media hypothesis in which there are two porosity-permeability relationships.
During the course of this paper, the work by Rida (3) was used at as it provides insights on how single medium dynamic models can be used to match and predict performance of a field with natural fractures in a carbonate formation, in Middle East. This work suggests the use of pseudo relative permeability curves that helped in estimating same performance/History match using a Single Porosity Single Permeability (SPSP) model compared to a Dual Porosity Dual Permeability (DPDP) model. Some scenarios tested in this work used the same permeability contrasts as observed in the field and yet yielded similar results in both SPSP and DPDP approaches, thereby reinstating the fact that a SPSP approach of modeling Natih-E formation should suffice.