No abstract

ADCO's oil and gas concessions onshore Abu Dhabi have several faulted structures including 3-way closure with fault seals within Cretaceous carbonate reservoir sequences. The prolific reservoir units have around 20–25% matrix porosity with tenths of mD permeability. The cap-rock of these reservoir units is mainly composed of a very dense carbonate with less than 5% porosity. A Geomechanical study was initiated with exploration objectives: (1) to understand the Geomechanical and geological rock properties variation closer to the fault (2) to evaluate the fault seal assessment for this complex faulted structure including Hydrocarbon Column (HC) height at exploration scale (3) uncertainties and its impact on fault seal assessment and (4) its application to exploration potential of the prospect. This paper discusses the sensitivity of different assumptions, Geomechanical parameters and hydrocarbon column height on structure and fault seal integrity, which influence exploration portfolio. A dedicated well was drilled and cored especially at the vicinity of few seismic faults to characterize the rock mechanical and petrological properties. Seismic semblance, core data and image log analyses across the fault have been carried out, together with Rock Mechanics Testing (RMT), which was very challenging due to selection of identical plug samples from similar depths. 1D Geomechanical models, which include in-situ stresses, pore pressure and rock strength and elastic properties for offset wells were built by integrating various data sets from this field. These calibrated 1D Geomechanical models are used to build 3D Geomechanical models and are further used for fault seal assessment. Results from core examination and thin section analysis show intense fracturing at the vicinity of the fault zones. Furthermore, there is micro-porosity loss clearly seen in thin sections as a result of cementation and digenesis. The seismic semblance, core data and image log analyses across the fault suggests that there is a significant uncertainty with dip magnitude of faults and this dip may range from 60° to 90°. The strike of these faults varies from N45W to N75W, typical fault orientations in Cretaceous formations of Abu Dhabi. While high porous reservoir rock is experiencing normal-stress setting, very dense cap rock is experiencing strike-slip stress setting. The strain along the fault-seal planes varied substantially depending on their dips and strikes and demonstrated different strengths under both predominant stress settings. Introduction The exploration portfolio of ADCO (Sirat et al., 2012) involves numerous leads and prospects and 42% of these plays represent three way closures with fault seals as shown in Figure 1. The built-up pressure from the height of the hydrocarbon column (HC), together with the pore-pressure and the in-situ stress magnitude control the integrity of the fault seals capacity. Fault slippage and reactivation was first recognized as a possible cause of fluid flow in faulted areas by Sibson (1985) and is fundamentally governed by the Mohr-Coulomb criterion. Analytical approaches usually simplify the problem to homogeneous and regular shaped reservoirs submitted to constant pore pressure and make use of closed-form solutions that range from simple Mohr-Coulomb failure relationships to provide fundamental solutions of elastic inclusions embedded in a halfspace (Geertsma, 1966, 1973; Segall, 1989, 1992; Zoback, 2007; Soltanzadeh and Hawkes, 2009). Zoback (2007) has extensively investigated this phenomenon in a detailed review.

KOC has undertaken an initiative to generate a regional in situ stress map for 23 Kuwait oil and gas fields using the data from more than 400 wells. Key objectives of this project are to integrate all available well data sources from these fields to derive the in situ stress orientation and also to create an interactive digital stress map supported by sub-surface structural geological data including formation seismic horizons, faults and well markers with the help of visualization software. In this way, the outcome of this project is available as an interactive geomechanical knowledge base which can be viewed at regional scale. The results of this project indicate that the maximum principal stress azimuth in Cretaceous formations is consistent with the regional Zagros tectonics and it is more or less uniform N45° (±10°) E direction even across major fault systems. However the sub-salt Jurassic formations exhibit high variability in stress orientation across faults as well as in the vicinity of fracture corridors. In addition to the patterns seen in stress orientation, the geomechanical models from each field exhibited that the Gotnia Salt is mechanically decoupling the highly stressed, strong, Jurassic formations from shallower, relatively lower stressed and weaker Cretaceous formations. It was also found that these stress anomalies in Jurassic formations coincide with associated fault and fracture corridors which appear to be critically stressed. Characterizing critically stressed fractures at the wellbore scale provided an understanding of possible permeable fracture sets that could contribute to gas flow. This paper discusses detailed results of the regional stress distribution patterns including innovative criteria developed to manage quality control of stress orientation data, correlation between stress anomalies and structural geological elements in Kuwait and also covers insights developed for exploration and development strategies of deep gas reservoirs in Kuwait. Introduction and Objectives Mapping of sub-surface structures and in situ reservoir properties have been in practice by explorationists for more than a century. The structural maps and profiles provide understanding of geological history and conditions that are essential for play evaluation. Many conventional oil & gas fields in the world have been explored and developed and many are at a mature state. However, limited data are available to map the present day in situ stresses in these fields, as typical conventional exploration techniques assume theoretical stress estimations based on a regional understanding of tectonic history related to the evolution of a particular field structure. Occasionally, seismic attributes have been used to complement these geological estimates. Consequently, there has been little appreciation of the influence of in situ stresses on exploration and development strategies. More recently, it has been realized that geomechanics plays a key role in various ways from exploration through field development including wellbore stability analysis (for improved drilling experience) to reservoir geomechanical analysis (for optimization of production).

Role of geomechanics is becoming increasingly important with maturing of conventional reservoirs due to its implications in drilling, completion and production issues. Exploration and development of unconventional reservoirs involve maximizing the reservoir contact and hydraulic fracturing both of which are heavily dependent on geomechanical architecture of the reservoirs and thus require application of geomechanical concepts from the very beginning.To support the unconventional exploration and conventional reservoir development in Kuwait, country-wide in-situ stress mapping exercise has been carried out in nine fields of Northern Kuwait. Stringent customized quality control measures were put in place to evaluate stress orientation. Cretaceous and sub-Gotnia Salt Jurassic rocks exhibit distinct patterns of stress orientations and magnitudes. While the variations in stress orientation in the Cretaceous rocks are within a small range (N40°E-N50°E) and consistent across major fault systems, the Jurassic formations exhibit high variability (N20°E-N90°E) with anomalous patterns across faults as well as in the vicinity of fracture corridors. Moreover, the overall stress magnitudes were found to be much higher in the strong Jurassic section compared with the relatively less strong Cretaceous strata. During the analysis, it was also observed that several natural fractures in Jurassic reservoirs appear to be critically stressed with evidences of rotation of breakouts.Using geomechanical models from a specific field, the effects of in-situ stress, pore pressure and rock properties on formations were evaluated in inducing wellbore instability during drilling operations in a tight gas reservoir. It was found that the most favorable orientation for directional drilling is parallel to the maximum horizontal stress (S Hmax ) within that field.The geomechanical study provided inputs not only for wellbore stability during drilling, but also regarding the response of natural fractures to in-situ stresses to become hydraulically conductive (permeable) to act as flow conduits. The fracture model of the field shows that the dominant fracture corridor trend in the field is NNE coinciding with present day in-situ maximum principal stress direction.