Application of Techniques of Natural Fracture Characterization for Appraisal of Tight Carbonate Reservoirs: A Case Study From Jurassic of Kuwait

The State of Kuwait is currently appraising and successfully developing the tight carbonates reservoirs of Jurassic age, which have very low matrix porosity and permeability. These reservoirs are affected by several tectonic events of faulting and folding, resulting in the development of interconnected natural fractures, which provide effective permeability to the reservoirs in form of production sweet spots. The objective of the study was to characterize the natural fractures and identify high permeability sweet spots as being appraisal drilling locations in a discovered field with tight carbonate reservoirs. An integrated approach was undertaken for building a discrete fracture network model by characterizing the developed faulting- and folding-related fractures and combining all subsurface data from multiple domains. The reservoir structure has a doubly plunging anticline at the field level that is affected by several strike-slip faults. The faulting-related fractures were characterized by generating multiple structural seismic attributes, highlighting subsurface discontinuities and fracture corridors. The folding-related fractures were modelled using structural restoration techniques by computing stresses resulting from the anticlinal folding. The fracture model was built in addition to the 3D matrix property model for this tight carbonate reservoir, resulting in a dual-porosity-permeability static model. Analogue data was used to compute fracture aperture and expected fracture porosity and permeability, to identify the sweet spots. Structural seismic attributes such as Ant Tracking and Consistent Dip were successful in highlighting and identifying the fault lineaments and fracture corridors. The seismic discontinuities were validated using the fractures interpreted in the image log data from the predrilled wells before being input into the fracture model. Paleo stresses, derived from structural restoration, were combined with the reservoir facies and geomechanical properties to gain important insight into predicting fractures developed due to folding. Several fracture aperture scenarios were run to capture the uncertainty associated with the computed fracture porosity and permeability. Based on the results, several sweet spots were identified, which were ranked based on their extent and connected volumes of the various permeability cases. Identifying these sweet spots helped make informed decisions regarding well planning and drilling sequence. High-inclination wells aligned parallel to the present-day maximum stress direction were proposed, which would cut across corridors of the predicted open fractures. Through this study, comprehensive fracture characterization and fracture permeability understanding of the tight carbonates in the field under study were successfully achieved. This workflow will be useful in exploratory or appraisal fields with tight carbonate reservoirs.

Towards the application of Stokes flow equations to structural restoration simulations

Structural restoration is commonly used to assess the deformation of geological structures and to reconstruct past basin geometries. For this, geomechanical restoration considers faults as frictionless contact surfaces. To bring more physical behavior and better handle large deformations, we build on a reverse-time Stokes-based method, previously applied to restore salt structures with negative time step advection. We test the applicability of the method to structures including sediments of variable viscosity, faults and non-flat topography. We present a simulation code that uses a combination of arbitrary Lagrangian–Eulerian methods and particle-in-cell methods, and is coupled with adaptive mesh refinement. It is used to apply the reverse-time Stokes-based method on simple two-dimensional geological cross-sections and shows that reasonable restored geometries can be obtained.

3D Natural Fracture Prediction Using Integrated Method of Structural Restoration and Geomechanical Forward Modelling: Case Study in South Sumatra Basin, Indonesia

Naturally fractured reservoir has important role in oil and gas development in onshore South Sumatra Basin Indonesia. There are several fields in Indonesia have hydrocarbon (oil or gas) potential in this type of reservoir. One of the fields is Northeast Betara operated by PetroChina International Jabung Ltd. The Northeast Betara structure consists of a basement high with tertiary burial that has been inverted due to compressive stresses during Late Miocene – Pliocene. The company plans to develop Lower Talang Akar Formation (LTAF) conglomeratic sand reservoir of Northeast Betara field which is believed to be naturally fractured. Well-B was drilled targeting conglomerate and fractured basement reservoir in the field. Unfortunately, even the Well-B intersected more fractures, the hydrocarbon test result was under expectation compared to previous Well-A 5 Km away, which encountered similar reservoir but shows better production test. Due to productivity discrepancy, this study is conducted to answer this issue by predicting natural fracture distribution across the field. An integrated structural restoration and geomechanical forward modelling is carried out thoroughly in order to better target the next well intersecting productive fractures. Structural restoration with finite element method provides layer geometries from initial deposition to the present day enabling explicit coupling with Stress Simulation engine at each geological time. Forward modelling could then be achieved by applying strain boundary conditions at the base of the model using known differential vertical displacement from one geological time to the next and lateral strain at the vertical boundaries of the model. Geomechanical forward modelling (GFM) simulates the evolution of structures of a geomechanical model from deposition up to present day and captures the geomechanical details with geological time. The main result of the study is plastic shear strains across the field, which subsequently converted into fracture density with orientation and inclination and can delineate the location of productive fractures. The fracture planes are defined by orientation and inclination matched over >85% of the observed fractures in the wells. Simulation results suggest that most fractures in the location of Well-A in the field are critically stressed and therefore expected to have better hydrocarbon production potential. This paper showcases approach of advanced geomechanical technique to predict 3D natural fracture distribution using existing data. The result will be used as reference to determine further development strategy.