La partie supérieure de la Formation Khuff est un réservoir représentant le plus grand champ gazier mondial, d'âge Permien supérieur à Trias inférieur. Il est formé de la succession de calcaires, de dolomies et de sulfates. Sa production est principalement contrôlée par des intervalles d'épaisseur généralement inférieure à 10 m, totalement dolomitisés, appelés super-drains ou super-K, connectés sur plusieurs dizaines de kilomètres.Les objectifs de l'étude sont (1) de définir la mise en place et l'extension des super-drains dans un cadre stratigraphique, (2) de comprendre la diagenèse contrôlant leurs propriétés réservoirs et (3) de comparer la mise en place des corps dolomitiques stratiformes précoces ou tardifs liés aux failles à ceux d'un analogue à l'affleurement, à savoir les formations calcaréo-dolomitiques d'âge Jurassique supérieur en Provence.Pour les atteindre, des analyses sédimento-diagénétiques (sédimentologiques, pétrographiques et géochimiques) ont été entreprises sur les deux objets d'études du réservoir de subsurface et de l'analogue réservoir d'affleurement. Pour ce dernier, une modélisation en 3D de corps diagénétiques liés aux failles a été réalisée. Les principaux résultats sont que :- les localisations des super-drains ont été contrôlées par la dynamique sédimentaire de séquences à basse fréquences (SBF) et à haute fréquence (SHF) ;- des super-drains sont localisés au sommet des SBF sous les discontinuités d'émersions et à la limite des fronts de dolomitisation de reflux différé. / The upper part of the Khuff Formation includes the biggest gas reserves in the world, from Upper Permian to Lower Triassic age. It is composed by the succession of limestone, dolomite and sulfate. The gas production is mainly driven by layers typically thinner than 10 m, fully dolomitised, and called super-drains or super-K and connected over several dozen kilometers.The goals of this study are (1) to define the formation and the extension of super-K layers in a stratigraphic framework, (2) to understand the diagenesis controlling their reservoir properties and (3) to compare the creation of early stratabound and late fault-related dolomite bodies with an outcrop analogue, from the limestone and dolomite formations from Provence from Upper Jurassic age.To reach this goal, sedimento-diagenetic analyses (sedimentological, petrographical and geochemical) have been carried out on studied objects, the subsurface reservoir and the outcrop analogue reservoir. For the latter, 3D modelling of fault-related dolomite bodies have been realised. The main results are:- the locations of super-K have been controlled by the sedimentary dynamics of low frequency sequences (SBF) and high frequency sequences (SHF) ;- some super-K are located at the top of SBF under emersion unconformities and at the rim of dolomitisation fronts associated to postponed reflux. The reflux was made of brines, coming from synsedimentary dolomite bodies associated with marine transgressions that followed the emersions. This model is corroborated by an outcrop analogue, which is a dolomite reservoir underlying a long lasting emersion unconformity;

Fluid flow mechanisms in a large naturally fractured heterogeneous carbonate reservoir were investigated in this manuscript. A very thin layer with high permeability that produces the majority of production from specific wells and is deemed the Super-K Zone was investigated. It is known that these zones are connected to naturally occurring fractures. Fluid flow in naturally fractured reservoirs is a very difficult mechanism to understand. To accomplish this mission, the Super-K Zone and fractures were treated as two systems. Reservoir management practices and decisions should be very carefully reviewed and executed in this dual continuum reservoir based on the results of this work. Studying this dual media flow behavior is vital for better future completion strategies and for enhanced reservoir management decisions. The reservoir geology, Super-K identification and natural fractures literature were reviewed. To understand how fluid flows in such a dual continuum reservoir, a dual permeability simulation model has been studied. Some geological and production iv data were used; however, due to unavailability of some critical values of the natural fractures, the model was assumed hypothetical. A reasonable history match was achieved and was set as a basis of the reservoir model. Several sensitivity studies were run to understand fluid flow behavior and prediction runs were executed to help make completion recommendations for future wells based on the results obtained. Conclusions and recommended completions were highlighted at the end of this research. It was realized that the natural fractures are the main source of premature water breakthrough, and the Super-K acts as a secondary cause of water channeling to the wellbore.

Fluid flow mechanisms in a large naturally fractured heterogeneous carbonate reservoir were investigated in this manuscript. A very thin layer with high permeability that produces the majority of production from specific wells and is deemed the Super-K Zone was investigated. It is known that these zones are connected to naturally occurring fractures. Fluid flow in naturally fractured reservoirs is a very difficult mechanism to understand. To accomplish this mission, the Super-K Zone and fractures were treated as two systems. Reservoir management practices and decisions should be very carefully reviewed and executed in this dual continuum reservoir based on the results of this work. Studying this dual media flow behavior is vital for better future completion strategies and for enhanced reservoir management decisions. The reservoir geology, Super-K identification and natural fractures literature were reviewed. To understand how fluid flows in such a dual continuum reservoir, a dual permeability simulation model has been studied. Some geological and production iv data were used; however, due to unavailability of some critical values of the natural fractures, the model was assumed hypothetical. A reasonable history match was achieved and was set as a basis of the reservoir model. Several sensitivity studies were run to understand fluid flow behavior and prediction runs were executed to help make completion recommendations for future wells based on the results obtained. Conclusions and recommended completions were highlighted at the end of this research. It was realized that the natural fractures are the main source of premature water breakthrough, and the Super-K acts as a secondary cause of water channeling to the wellbore.

Many attempts have been made to control water conformance. It is very costly to produce, treat and dispose of water, and produced water represents the largest waste stream associated with oil and gas production. The production of large amounts of water results in: (a) the need for more complex water?oil separation; (b) corrosion of wellbore and other equipment; (c) a rapid decline in hydrocarbon production rate and ultimate recovery; and (d) consequently, premature abandonment of a well or field, leaving considerable hydrocarbons unproduced. Sometimes water production results from heterogeneities in the horizontal direction, which leads to uneven movement of the flood front and subsequent early breakthrough of water from high permeability layers. This problem is exacerbated if there is (vertical) hydraulic communication between layers so that crossflow can occur. One of the novel technologies in chemical enhanced oil recovery (EOR) is a gel type called deep diverting gel (DDG), which describes material that functions by plugging thief zones deep from the well where they were being injected. To evaluate the performance of this new treatment method, we will (1) model the treatment methods, (2) conduct economic analysis, and (3) compare different EOR methods. We have conducted relevant literature review about the development, design, modeling and economics of the enhanced oil recovery methods. Schlumberger's Eclipse simulator software has been used for modeling purposes. Modeling runs have demonstrated that placement of a DDG in a high permeability zone provided a blockage that diverted water into lower permeability areas, thus increasing the sweep of target zones. Research results demonstrated that, although higher recovery can be achieved with a polymer flood, the combination of delayed production response and large polymer amounts cause such projects to be less economically favorable than deep gel placement treatments. From results of several sensitivity runs, it can be concluded that plug size and oil viscosity are two determining factors in the efficiency of DDG treatments. For the assumed case, economic analysis demonstrated that DDG has the most positive net present value (NPV), with polymer flooding second and simply continuing the waterflood to its economic limit the least positive NPV.

This work was conducted to help understand a premature and irregular water breakthrough which resulted from a waterflooding project in the increment II region of Haradh oilfield in Saudi Arabia using different geophysical methods. Oil wells cannot sustain the targeted oil production rates and they die much sooner than expected when water enters the wells. The study attempted to identify fracture systems and their role in the irregular water sweep. Single-well acoustic migration imaging (SWI), walkaround vertical seismic profiling (VSP) and cross-dipole shear wave measurements were used to detect anisotropy caused by fractures near and far from the borehole. The results from all the different methods were analyzed to understand the possible causes of water fingering in the field and determine the reasons for discrepancies and similarities of results of the different methods. The study was done in wells located in the area of the irregular water encroachment in Haradh II oilfield. Waterflooding was performed, where water was injected in the water injector wells drilled at the flanks of Harahd II toward the oil producer wells. Unexpected water coning was noticed in the west flank of the field. While cross-dipole and SWI measurements of a small-scale clearly identify a fracture oriented N60E in the upper tight zone of the reservoir, the VSP measurements of a large-scale showed a dominating fracture system to the NS direction in the upper highpermeability zone of the same reservoir. These results are consistent with the directions of the three main fracture sets in the field at N130E, N80E and N20E, and the direction of the maximum horizontal stress in the field varies between N50E and N90E. Results suggested that the fracture which is detected by cross-dipole at 2 to 4 ft from the borehole is the same fracture detected by SWI 65 ft away from the borehole. This fracture was described using the SWI as being 110 ft from top to bottom, having an orientation of N60E and having an angle of dip of 12° relative to the vertical borehole axis. The detected fracture is located in the tight zone of the reservoir makes a path for water to enter the well from that zone. On the Other hand, the fractures detected by the large-scale VSP measurements in the NS direction are responsible for the high-permeability in the upper zone of the reservoir.