The aim of this study is to propose a stratigraphic and sedimentary framework though the integration of available sedimentary, diagenetic and petrophysical data, which will be utilized in the construction of a high resolution stratigraphic framework, as an input into comprehensive review and update of an existing model of heterogeneous carbonate reservoir in a mature field in Abu Dhabi, UAE.
Depositional facies have been defined in cored wells, subsequently were associated taking into account the biologic and sedimentary processes in response of carbonate growing and sea level changes, allowing the identification of the main stratigraphic surfaces.
Surfaces can extend the correlation along the field and define the model of facies that, with the evidence provided by cores, can recreate and predict the different regressive-transgressive cycles in high resolution which the carbonate platform were undergone during its evolution.
Diagenetic evolution, interpreted through laboratory observations, was integrated with facies and petrophysical evaluation allowing the understanding of the spatial distribution of petrophysical properties within a heterogeneous reservoir and define a new set of facies which will be used in the generation of geological static model.
Application of sequence stratigraphy methods in cores, and extended in logs allowed the identification of six depositional sequences, with thicknesses of 2 to 4 meters each, corresponding to the phases of carbonate platform growth. Within each depositional sequences, typical cycles were defined that support the understanding in the association of facies and their relationship during the deposition.
The identification of sedimentological cycles not only genetically organizes the facies and predicts the stacking pattern, but also makes possible to find an excellent correspondence between cycles from lowstand system track intervals with good to excellent permeability values, and cycles from transgressive system track intervals with low permeabilities.
Many of the sequence stratigraphy published articles driven for the most important reservoirs along the Arabian Plate, provide an excellent tool in the regional correlation. However, they are not enough to be used in the reservoir characterization in detail that is required during the development of the field neither as input data in the generation of geological static models that use the sedimentary trends as constrain to populate the petrophysical properties.
In the Sab'atayn Basin of Yemen hydrocarbons were generated from pre-salt Upper Jurassic source rocks during the Cenozoic and the salt provides the ultimate seal for the pre-salt and intra-salt traps. Therefore the proper understanding of salt tectonics is critical for ongoing hydrocarbon exploration efforts in the Sab'atayn Basin.
A variety of distinct salt tectonic features are present in the Sab'atayn Basin. Based on the regional interpretation of 2D seismic and locally available 3D seismic reflection data calibrated by exploration wells in the central part of the basin, an Upper Jurassic evaporite formation ("salt" from this point on) produced numerous salt rollers, pillows, reactive, flip-flop, active and falling diapirs.
Due to regional extension, halokinetics began by formation of salt rollers, as soon as the early Cretaceous, within just a few million years after the deposition of the Tithonian Sab'atayn Formation. The salt locally formed salt pillows which evolved to salt diapirs and diapiric salt walls as the result of renewed extension in the basin. As the result of a prominent extensional episode at the end of the Cretaceous most of the diapiric walls in the basin are controlled by large normal faults on their updip flanks. Some of the diapiric walls even evolved into falling diapirs due to ongoing extension
As the Sab'atayn Formation has typically several massive salt intervals in it, it defines post-, intra- and pre-salt play types in the basin. However, other than just providing traps and seals in the basin, salt tectonics is also very important for source rock maturation in the basin. As there are many salt diapirs in the study area, their cooling effect on the the pre-salt hydrocarbon kitchens appears to be quite significant, based on our preliminary basin modelling efforts.
John, Cédric M. (QCCSRC and Earth Science and Engineering, Imperial College London) | Hönig, Martin R. (QCCSRC and Earth Science and Engineering, Imperial College London) | Abbott, Sunshine (QCCSRC and Earth Science and Engineering, Imperial College London) | Fraser, Alastair J. (Earth Science and Engineering, Imperial College London)
Most regional studies of reservoir and seals focus on large-scale sequences and their architecture. However, understanding flow and geochemical processes happening in the subsurface requires a multi-scale approach from the pore-size to the field-size. Here we focus on an intermediate, ‘inter-well’ scale loosely defined as 100-1000 meter scale. This inter-well scale is crucial as it represents the minimum distance between an injector and a producing well. Hence, constraints on the heterogeneities in the reservoir or within a sealing lithology can guide the production geologist during EOR or CCS operations. In this paper, we present a review of existing outcrop analogues for the subsurface of Qatar that were considered for our study. Out of the different possibilities, we selected outcrops from Wadi Naqab (Ras-Al-Khaima, UAE) as an analogue for the subsurface reservoirs in Qatar, and we focused on mine outcrops in the U.K. as potential analogues to derive the 3D geometry of evaporite-carbonate sequences analoguous to the Hith Formation. The Jurassic limestones at Wadi Naqab appear layer cake at the scale of observation, but we demonstrate here that even though beds rarely pinch out, the facies within bed changes markedly at a scale of <200 meters. For subsurface applications, this could be significant if the change in facies correlates with a change in petrophysical properties. The anhydrite layers at Brightling Mine are mostly composed of nodular, sabkha-type layers, inter-bedded with shallow-water algal limestones and shales. These lithologies are continuous at a 500 meters scale, but scouring impacts on the thickness of the deposits. Again, this could have important mechanical implications during CCS operations, because the interface of different lithologies and their thicknesses control fracture propagation within reservoirs and seals. We conclude that more geometrical heterogeneities exist in both reservoir and seals than previously thought, and that inter-well scale data are needed to inform subsurface reservoir models. We also caution that one of the limitations of using outcrop analogues is that porosity and permeabilities are not preserved during uplift, and thus petrophysical properties within numerial reservoir modelling need to be populated using subsurface data.
Vahrenkamp, Volker C. (ADCO) | Van Laer, Pierre (ADCO) | Franco, Bernardo (ADCO) | Celentano, Maria Agustina (ADCO) | Grelaud, Carine (University of Bordeaux) | Razin, Philippe (University of Bordeaux)
The occurrence of major hydrocarbon prone Mesozoic source rock sequences of the eastern Arabian plate is directly tied to the generation of intra-shelf basins within the giant carbonate platforms that formed during this time period. This paper investigates the driving forces behind the formation of intra-shelf basins and related source-rock/seal sequences. Results impact topics such as exploration, reservoir distribution, regional tectonics and climate modelling.
A combination of large scale regional stratigraphic correlations, age dating, geochemical indicators and global climatic/tectonic events are investigated to explain differences and commonalities in basin formation and their impact on source rock seal pairs.
In the Mesozoic major intra-shelf basins existed during three time periods: in the Late Jurassic during the Oxfordian to Tithonian, and in the Cretaceous during the Aptian and the Cenomanian.
The late Jurassic basin is predominantly generated by plate margin tectonism possibly in conjunction with the rejuvenation of major WNW-ESE and N-S basement structures. Uplift at the eastern plate margin during the late Jurassic caused exposure at the eastern plate margin towards the Neo-Tethys, which in combination with sea level fluctuations resulted in the deposition of several large scale cycles. In central Abu Dhabi westward progradation of the Tuwaiq Mountain, Hanifa and Jubaila Sequences into an intrashelf basin are key evidence for the eastern uplift as are large scale collapse features reported from the eastern margin itself. The widespread deposition of the Arab and Hith anhydrites in the interior of the eastern Arabian plate are taken as further evidence for tectonically driven basin isolation leading to restricted evaporitic conditions.
In contrast, the Cretaceous Aptian and Cenomanian intra-shelf basins formed mainly as a consequence of environmental/climatic disturbances associated with global oceanic anoxic events. During these times of global climate stress carbonate sedimentation was unable to keep up in areas with relatively high subsidence rates and laterally segregated providing the impulse for a switch from flat-topped platforms to a nascent basin topography (Hawar & Thamama A/Shuaiba during the latest Bar/Early Aptian; AP Apt 1), and Mauddud FM (latest Albian). Subsequent differential aggradation in combination with continued subsidence led to the full development of the basin topography in the early Aptian (AP Apt2–4; Bab Basin) and early Cenomanian (Shilaif Basin). Significantly, detailed carbon isotopic data indicate that climatic disturbances and the onset of oceanic anoxic events correspond to the generation of the initial topography and not to the onset of the deposition of organic rich basin fill sediments. Subsequent to deposition of organic rich sequences Cretaceous intra-shelf basins are dominated by argillaceous limestones and siliciclastics (Bab basin: Upper Bab Member - AP Apt5 and basal Nahr Umr AP-Apt6; Shilaif Basin: lower & upper Tuwayil FM).
Thus, basin fill differs significantly between the late Jurassic tectonic basin featuring evaporate seals (Arab and Hith FM) and the Cretaceous climatic/constructional intrashelf basins being covered by clastic-rich sequences.
Finally, it is postulated that the formation of another intra-shelf basin associated with the Valenginian Oceanic Anoxic Event (OAE1) was prevented by a regional tectonic uplift and platform exposure during the Late Valenginian.
Well bore stability management is key to HSSE and cost effectiveness while drilling. This work focuses on the role of Geosciences to understand, explain and better predict the occurrence of well bore stability issues during onshore drilling operations in Block S2, central Yemen.
To reach the primary reservoir target, the fractured Basement, development wells must penetrate a complex stratigraphic column, characterized by ten key formations and approximately 2000 meters thick. Lithologies vary from sandstones to carbonates, including salt layers with clay intercalations. Severe mud losses are often encountered in poorly consolidated sands of the Lower Tawilah formation where well inclinations are vertical or sub-vertical. At their most severe, they can translate to a complete loss of drilling mud returns on surface. Severe mud losses are not only a threat to borehole stability but they can have a serious impact on the drilling budget and timing.
In order to improve drilling efficiency and speed-up the decision-making process associated with mud losses management and well stability, a detailed Geoscience study has been carried out. This work focuses on identifying three critical factors to explain the occurrence of severe losses:
Despite the challenging working environment and the interaction of geological heterogeneity, pore pressure and stress across the development area, the prediction and prevention of mud losses has been greatly improved while drilling new wells.
The main objective of this paper is to highlight the role these three major elements play during drilling by illustrating with case study examples. Finally, mitigating actions and strategies implemented to prevent and/or deal with severe drilling mud losses are presented.
The area of Interest is located in the northern branch of the Sab’atayn Basin (Marib-Al Jawf-Shabwah Basin), which is a NW-SE trending late Jurassic intra-cratonic rift basin, which lies in southwestern Yemen (Figure 1). The NW-SE trend of the Yemeni Mesozoic rifts reflects an inheritance from deep-seated Precambrian structural trends observed throughout the Arabian Plate, known as the Najd trend. The generalised stratigraphy of the area is shown in Figure 2. This paper particularly focuses on the issues arising while drilling through the Lower Tawilah Fm.
John, Cédric M. (Imperial College London) | Vandeginste, Veerle (Imperial College London) | Jourdan, Anne-Lise (Imperial College London) | Kluge, Tobias M. (Imperial College London) | Davis, Simon (Imperial College London) | Sena, Claire (Imperial College London) | Hönig, Martin (Imperial College London) | Beckert, Julia (Imperial College London)
Petroleum geologists working in carbonate plays are facing two common and inter-connected challenges linked to optimizing production. First, constraining the geometry, spatial distribution and inter-connectivity of reservoir geobodies is crucial as these properties can control the permeability anisotropy of reservoirs zones. This is difficult to do at the inter-well scale due to the limited resolution of seismic methods (20 meters or higher) compared to the size of typical reservoir geobodies (tens of centimers to meters and higher) and the very heterogeneous nature of carbonate reservoirs. Furthermore, diagenetic transformations are very important in carbonate reservoirs. Being able to fingerprint the process and timing of diagenetic transformation is crucial to a correct assessement of the distribution of cemented zones in the subsurface. The issue of diagenesis is also important for organic matter maturation and the timing of oil migration, and therefore the second challenge faced by reservoir geologists in carbonate plays is one of constraining as well as possible the thermal history of the targeted basin. This paper reports on the results of a major long-term research effort that addresses some aspects of this double challenge in the Middle East, and that focused on novel isotopic methods to constrain the thermal history of carbonate phases in the context of the geometry of geobodies measured at the outcrop. Geological work under the Qatar Carbonates and Carbon Storage Centre (QCCSRC), funded jointly by Qatar Petroleum, Shell and the Qatar Science & Technology Park, has as its long-term research goals to improve characterization of subsurface anisotropies in carbonate reservoirs, notably for CCS operations.
The overall approach of the QCCSRC team has been to do extensive fieldwork in the Middle East in order to constrain some aspects of the dimension of inter-well carbonate geobodies, but also to focus on fundamental research on applying the novel ‘clumped isotope' method to subsurface relevant problems. The field of clumped isotopes paleothermometry is concerned with the state of isotopic ordering of carbonate minerals. More precisely, the clumped isotope paleothermometer relies on measuring the abundance of 18O-13C bonds within the lattice of a carbonate mineral and determining the offset between this abundance and a stochastic (random) distribution of isotopologues at high-temperature (nominally 1000°C, Wang et al., 2004). Both 18O and 13C are heavy, rare isotopes, and the ‘clumping' of the two heavy isotopes into the lattice of a carbonate mineral is extremely rare (the natural abundance of the resulting CO2 of mass 47 is around 44 ppm, Eiler, 2007). But more importantly isotopic ‘clumping' is governed by thermodynamic principles: at low temperature, ‘clumping' of heavy isotopes is favored because the vibrational energy in a heavy-heavy bond is more than twice lower than the corresponding light-light bond, and the molecule consequently is more stable. At high temperatures, the effects of entropy mask the effects of clumping, giving rise to a stochastic distribution of isotopologues. The ‘clumping' parameter is denoted D47 and is defined as:
This paper presents the workflow and the results of integration of seismic, well and production data on Habban Field to optimize well locations.
Habban Field is located in the Jurassic Marib-Al Jawf-Shabwah basin of Yemen (Block S2). Development targets in Habban Field are fractured Precambrian Basement, Kohlan and Shuqra formations (Middle Jurassic).
Main challenges faced in the Field are Basement heterogeneity, fracture distribution and their connectivity, lateral variation of Kohlan Formation and the overlying salt diapirs/walls hampering the seismic imaging. The difference between a good and a dry well is whether it is encountering main fracture corridors or not. Fracture corridors (along the faults) have limited lateral extent and due to overlying salt diapirs well trajectory optimization is very challenging. Reflection pattern in the Basement is quite chaotic. Therefore, it was important to come up with a workflow to image faults within the Basement so that highly deviated to horizontal wells can be drilled to enhance production and optimize recovery.
In order to address these challenges, wide azimuth 3D seismic was acquired and processed in different azimuths. The study has been conducted using 3D seismic dataset and derived seismic attributes combined with information from thirty one wells including image and production log interpretation. The workflow highlighted the value of G&G integration to better outline uncertainty and to mitigate risks during well locations and trajectory planning. In this contest structural attributes (i.e. Ant-Tracking) have been crucial in order to define and identify the faults zones for optimizing horizontal wells targeting multiple fracture zones.
On the other hand integration of G&G and production data highlights the limitation in defining a one-to-one correlation between seismic, well and production information mainly due to reservoir complexity and scale resolution.
Warrlich, Georg Mathis (PDO) | Amthor, J. (Petroleum Development of Oman) | Abu-shiekah, Issa M. (Shell Development Oman LLC) | Al-Kharusi, Ahmed Said (Petroleum Development of Oman) | Al-Kindy, Mohammed Hilal (Petroleum Development of Oman) | Garimella, Sai V.S. (Petroleum Development of Oman)
Despite the economics and environmental benefits of PWRI (Produced Water Re-Injection) projects, the permeability reduction due to deposited particles is a persistent problem. Various models for permeability damage calculation are available. Most of them are based on one-dimensional laboratory parameters and have not considered the anisotropy of the media. In previous attempts at anisotropy modelling, the initial anisotropy of the media has been considered. However, when it comes to the damage intensity calculation, isotropic parameters have been used for the entire media. As a result, the relative damage in these models is isotropic.
In this paper, a robust approach for anisotropic permeability impairment is developed based on micromechanical considerations. The damage mechanics is coupled with numerical flow code. The model formulation has been successfully tested in 1D flow against the core flood tests from the Masila Block onshore Yemen. Then, the damage model has been extended to 3D using pseudo directional parameters to capture the anisotropy. A dynamic anisotropic mathematical formulation for damage intensity has been derived, implemented in a 3D numerical code and successfully tested on a field case study. The new model exhibits the expected anisotropy of damage.