Field presented here is located in offshore Abu Dhabi, consisting of multi-stacked reservoirs with different fluid and reservoir properties. In this paper, field development plan of one of reservoir has been presented which was initially planned to be developed with pattern water injection by more than 50 horizontal wells penetrating all the ten oil bearing layers from 9 well head towers. Reservoir consists of under-saturated oil with low gas-oil ratio and low bubble point. Initial 2 years of production was considered as Early Production Scheme (EPS period), during which significant amount of early production data consisting of downhole pressure measurement, time-lapse MDT, vertical interference data, PLT have been collected. Based on EPS data simulation model has been updated. Simulation fits well with the observed pressure gauge and time-lapse MDT data. Updated model gives good prediction for a year of blind test data (including saturation, MDT and porosity) collected from different wells several kilometers away from current development area reflecting a high level of confidence in areal and vertical connectivity representation. Considering other reservoir uncertainties different Development plans have been screened using updated model in order to improve recovery factor and economics. Based on development plan screening study, optimized development option has been chosen for Full Field Development.
BinAbadat, Ebtesam (ADNOC Offshore) | Bu-Hindi, Hani (ADNOC Offshore) | Al-Farisi, Omar (ADNOC Offshore) | Kumar, Atul (ADNOC Offshore) | Zahaf, Kamel (ADNOC Offshore) | Ibrahim, Loay (ADNOC Offshore) | Liu, Yaxin (ADNOC Offshore) | Darous, Christophe (Schlumberger Oil Company) | Barillas, Luisa (Schlumberger Oil Company)
Reservoir Rock Typing and saturation modeling need a two-sided methodology. One side is the geological side of the rock types to populate properties within geological concepts. The other side is addressing reservoir flow and dynamic initialization with capillary pressure. The difficulty is to comply with both aspects especially in carbonates reservoirs with complex diagenesis and migration history. The objective of this paper is to describe the methodology and the results obtained in a complex carbonate reservoir.
The approach is initiated from the sedimentological description from cores and complemented with microfacies from thin sections. The core-based rock types use the dominant rock fabrics, as well as the cementation and dissolution diagenetic processes. The groups are limited to similar pore throat size distribution and porosity-permeability relationships to stay compatible with property modeling at a later stage.
At log-scale, the rock typing has a focus on the estimation of permeability using the most appropriate logs available in all wells. Those logs are porosity, mineral volumes, normalized saturation in invaded zone (Sxo), macro-porosity from borehole image or Nuclear Magnetic Resonance (NMR), NMR T2 log mean relaxation, and rigidity from sonic logs. A specific calculation to identify the presence of tar is also included to assess the permeability better and further interpret the saturation history. The MICP data defined the saturation height functions, according to the modality of the pore throat size. The log derived saturation, and the SHFs are used to identify Free Water Level (FWL) positions and interpret the migration history.
The rock typing classification is well connected with the geological aspects of the reservoirs since it originates from the sedimentological description and the diagenetic processes. We identified a total of 21 rock types across all the formations of interest. We associated rock types with depositional environments ranging from supra-tidal to open marine that controls both the original rock fabrics and the diagenetic processes. The rock typing classification is also appropriate to model permeability and saturation since core petrophysical measurements were in use during the classification. The permeability estimation from logs uses multivariate regressions that have proven to be sensitive to permeability after a Principal Component Analysis per zones and per lithologies. The difference between the core permeability and the permeability derived from logs stays within one-fold of standard deviation as compared to the initial 3-fold range of porosity-permeability. We assigned the rock types with three Saturation Height Function (SHF) classes; (unimodal-dolomite, unimodal- limestone & Multimodal-Limestone). The log derived water saturation (Sw) from logs and SHF shows acceptable agreement.
The reservoir rock typing and saturation modeling methodology described in this paper are considerate of honoring geological features and petrophysical properties to solve for complex diagenesis and post-migration fluid alteration and movement processes.
Xi, Guifen (ADMA-OPCO) | Singh, Rudra (ADMA-OPCO) | Haddad, Mohamed (ADMA-OPCO) | Lecoq, Thierry Francis (ADMA-OPCO) | Al Badi, Bader Saif (ADMA-OPCO) | Zahaf, Kamel (ADMA-OPCO) | AL-Kindi, Rashid Khudaim (ADMA-OPCO) | AL-Wahedi, Khalid Ahmed (ADMA-OPCO) | Leblanc, John (ADMA-OPCO) | Singh, Hemant (Baker Hughes) | Perumalla, Satya (Baker Hughes) | Salter, Tim (Baker Hughes) | Imtiaz, Saad (Baker Hughes) | Kirby, Cliff (Baker Hughes) | Paila, Phalgun (Baker Hughes)
ADMA-OPCO has undertaken a prestigious campaign to drill a large number of wells from artificial island in ABC field, most of these wells are extended reach drilling (ERD) wells with step-out up to around 18,000 ft. Operational efficiency/costs for drilling ERD wells is highly dependent on the wellbore stability, especially while drilling through the problematic Nahr Umr shale at different deviations and azimuths. Nahr Umr shale has a known history of causing wellbore instability in UAE and the surrounding countries and therefore a geomechanical study was initiated to understand the geomechanical setting in ABC field as well as fluid-rock interaction between drilling fluid and Nahr Umr shale formation. The main objectives of this geomechanical study were to optimize well design and drilling fluids in order to drill through Nahr Umr shale interval efficiently, additionally estimation of sustainable pressure variation that major faults can take without being reactivated was also performed.
An integrated geomechanical study including a 3D geomechanical modeling was carried out, in order to ensure drilling through Nahr Umr shale formation efficiently. This study covered formation petrophysical characterization, chemical tests on cuttings from Nahr Umr shale, chemo-poroelastic modeling, weak bedding analysis and also faults reactivation analysis.
Based on the study mentioned above, both customized drilling fluids program and suitable mud weights were optimized to stabilize Nahr Umr shale, and mitigate different types of wellbore instability issues. In addition to mud fluid optimization, the sustainable pore pressure variation was also estimated for several major faults.
A successful drilling campaign is in progress; so far many deviated wells have been completed without any noticeable troubles while drilling through Nahr Umr shale. This geomechanical model is helping to implement an effective drilling program for a smooth well placement. A learning curve has been building up continuously for handling more complex well trajectories successfully in the future. From this study, it was realized that, not only fluid-rock interaction and geomechanics related factors need to be taken into consideration for stabilizing a wellbore, but also special attention is needed for the existing micro-fractures within the formation, where increase in mud weight may make hole condition worse. A balanced approach has been adopted including drilling fluid optimization in order to avoid possible multiple failure mechanisms.
Li, Hongxia (Masdar Institute of Science and Technology) | Yang, Weilin (Masdar Institute of Science and Technology) | Huang, Haibo (Masdar Institute of Science and Technology) | Chevalier, Sylvie (Masdar Institute of Science and Technology) | Sassi, Mohamed (Masdar Institute of Science and Technology) | Zhang, TieJun (Masdar Institute of Science and Technology) | Zahaf, Kamel (Abu Dhabi Marine Operating Company) | Al-Farisi, Omar (Abu Dhabi Marine Operating Company)
Rock surface wettability is one of the most important factors impacting the oil recovery efficiency. Carbonate reservoir rocks show highly heterogeneous wettability, which is imposing big challenges in Enhanced Oil Recovery. Because of the complicated porous morphology and interaction between oil/water phases, the mechanism of how surface wettability affects the relative permeability is still unclear. In this work, we develop a Lattice Boltzmann method (LBM) to study the oil-water-rock interaction through systematic water-flooding simulations. Our LBM model is validated by the analytical solution of co-current oil-water flow and lab-scale microchannel oil displacement experiment. To further investigate the effect of rock surface wettability and reveal the pore-scale oil trapping mechanism, a series of water-flooding oil displacement simulations are conducted under different initial oil saturation and surface wettability conditions. For realistic pore-scale flow visualization, a 2D micro-CT image of carbonate rock in Abu Dhabi is used. Our simulation results indicate that the surface wettability has significant influence on the volume of trapped oil at the end of the recovery process; the trapped oil residue in an oil-wet pore could be 2.5 times more than that in a water-wet pore. This study is an important step toward understanding the complicated oil trapping mechanism in heterogeneous carbonate reservoirs with variable wettability conditions.