Vijaya Kumar Kidambi

Structural Evolution Model for the North Kuwait Carbonate Fields and its Implication for Fracture Characterisation and Modelling

This paper presents a new structural model for the North Kuwait Carbonate fields as well as its implications in term of fracture modelling and field development. It also describes a workflow which can be used as foundation for further fracture modelling study at production and exploration scales alike. This workflow consists of a four step approach: 1) elaboration of a regional structural model, 2) creation of 3D conceptual fracture diagrams, 3) elaboration of constraints capturing the key elements of the conceptual diagrams and 4) creation of fracture model properties for further dynamic simulation. The application of this workflow resulted in the creation of a series of fracture models for the North Kuwait Carbonates fields. During the first step of the study, a new structural model has been elaborated based on key kinematic observations from well and seismic data, as well as experimental and field analogues which have been linked to the known regional phases of deformation. These main phases of deformation are 1) post Triassic rifting, 2) Alpine 1 - late Cretaceous transtension and 3) Alpine 2 - Mid Tertiary compression related to the Zagros formation, which has the greatest impact on the formation of the pre-Gotnia structures and fracture development. The major difference between the new model and previous structural thinking is that the formation of the compressional folds in the Carbonate fields (an event that shaped the current outline of the fields) has happened during the Tertiary time instead of Jurassic time. The proposed structural evolution has been used to define characteristic structural domains. These structural domains have defined a foundation to elaborate conceptual fracture diagram to support fracture modelling study work. The fracture conceptual models have potential implications on fracture development and preferred direction of horizontal and deviated wells. Greater fracture connectivity is expected in compressional ridges developed in Tertiary time, while in the area between the compressional ridges, less dense fractures and probably more cemented fractures (likely to have developed before hydrocarbon emplacement ) are expected. The new view on the timing of the structural development (i.e., late uplift of compressional ridges regionally) also has possible implications on maturation/charge history as well as reservoir properties development. The new proposed model for structural evolution is now being used as a foundation for appraisal and fracture modelling activities of the pre-Gotnia carbonate reservoirs. A fracture characterisation study integrating all available static and dynamic data is ongoing.

PP Azimuthal-amplitudes And -acoustic Impedance For Fractured Carbonate Reservoir Characterization

Four azimuth-sectored 3D P-P volumes were pre-stack time migrated (PSTM) using the same velocity field. These high-fold full-azimuth full-offset data (4,000-5,000 traces were summed in each bin in each azimuth sector) of high S/N enable azimuthal analysis of amplitudes, and acoustic impedance, at the top of the reservoir unit of interest (14,000 ft depth). Each azimuthal cube was inverted for acoustic impedance after prestack time migration. These high-fold azimuth-sectored PSTM 3D data enable us to determine the azimuthal variation of amplitudes, and acoustic impedance, assuming orthorhombic symmetry (flat layers and one set of vertical aligned frctures), and so map relative fracture density and fracture azimuth of the open fractures that flow hydrocarbons in the reservoir unit. The N-S natural fracture strike seen at Well A in the reservoir unit are parallel to the local max hor stress, as interpreted through borehole breakout and the induced fractures. The N-S trending fractures at Well B cause the fracture-parallel amplitude to be the azimuthal minimum, for the top of this low-impedance reservoir. The acoustic impedance inversions showed max acoustic impedance N-S, parallel the fractures and max hor stress, corroborating the interpretation of the azimuthal amplitudes, and tieing the well data. The spatial heterogeneity of the fractures in the upper part of the reservoir unit is mapped using the azimuthal variation of PP amplitudes, and acoustic impedance, after fitting to the cosine 2theta curve.

Building a Seismic-driven 3D Geomechanical Model In a Deep Carbonate Reservoir

In this paper we show how to extend seismic-driven earth model building into the domain of geomechanics and drilling. A mechanical earth model (MEM) is a quantitative description of rock mechanical properties and in-situ stresses in the subsurface. Formation strength and in-situ stress are key components that impact well design. Most mechanical earth models, even today, are one-dimensional (1D), based on well and drilling data alone. The concept of using seismically derived horizons and velocities to extend the MEM into 3D space was introduced a few years ago. Very recently, a few authors have demonstrated the power of seismic inversion to improve the resolution and quality of a 3D MEM. We present a case-study from Kuwait (Sabriyah field) where a 3D geomechanical model was built using a combination of wellbore geomechanics, geologic structure, and seismic inversion-derived lithofacies and elastic properties. We show critical challenges facing seismic-based geomechanical model-building, demonstrate current solutions, and discuss future strategies.

Field Development and Well Planning in Tight Carbonate Reservoir Using Fracture Characterization and In-Situ Stress Mapping From Core Reorientation Studies: Kuwait Case Study

Fracture characterization is vital for efficient field development of naturally fractured Carbonate reservoirs. Successful development of fracture reservoir in the study area was possible due to early recognition of fracture play right from the exploration phase and through careful execution of relevant data acquisition campaign in the initial stages of field development. Comprehensive and integrated studies have been carried out over the past few years to arrive at an understanding of the conceptual model in deciphering structural evolution of North Kuwait Jurassic. Extensive core and image log data was acquired in the initial stages of field appraisal, which helped in comprehensive forward planning in design of deviated and horizontal wells. The data analysis steps included accurate and reliable reorientation of the cores. These data were calibrated with the image logs, along with available seismic attributes, which resulted in better understanding of structural evolution and sweet spotting of horizontal wells. This reorientation of the core data also helped in establishing a number of quantitative fractures attributes such as frequency, spacing, dip-azimuth and aperture along with mapping of in-situ stress directions. The detailed integration of these data also helped in accurately mapping the local and regional present day stress and its variations spatially across the fields. Stress direction across the field was helpful for deciding the azimuth of wells during well planning along with selection of completion strategy for current set of horizontal drilling Campaign. Drilling and testing results have been encouraging through enhanced reservoir performance in these tight carbonate reservoirs, based on these integrated studies.

Sweetspotting of the First Appraisal Campaign of Unconventional Resource Play in Kuwait

Organic rich Kerogen layer of Lower Kimmeridgian to Upper Oxfordian age, deposited throughout Kuwait, is a TOC rich layer with varying TOC content between 2 to 20 wt% (in the vertical section) and having an average TOC of about 8 wt%. The depth of occurrence of this layer favorably places this zone to be having potential in rich gas condensate resource in the northern part of Kuwait. This layer occurs at a depth of 14000-16000 ft with a reservoir temperature of 270⁰-275⁰F, pressure of 11000 psi and average thickness of over 50ft. This is one of the main source rocks for majority of the oil and gas fields of Kuwait. This Kerogen section is penetrated through a number of vertical wells, as part of development of deeper reservoirs in this area, which offers an excellent opportunity to evaluate this section through core and open-hole log data. Because of the strong acoustic contrast with the overlying and underlying layers, this reservoir section is a very strong mappable seismic reflector. As part of appraising the potential of this layer, as a resource play, a comprehensive success criteria has been worked out for location selection. An integration of all available geo-scientific data such as geochemical, 3D seismic attributes, petrophysical analysis, borehole image interpretations, geo-mechanical, core and mud logs has been carried out. The above data integration/analysis was combined with the success criteria, leading to selection of sweet-spots for planning the first dedicated horizontal well targeted on this layer. This paper presents the success criteria worked out and the integration of data for high grading the locale – sweet-spots, for the first set of horizontal wells for appraising this deep HP-HT unconventional play of Kuwait.