Shale and tight gas reservoirs consist of porous structures with pore diameter in the range of some mm to m. At these scales, the pore diameter becomes comparable to the gas mean free path. Flows in these structures fail often in the transition and slip regimes. Standard continuum fluid methods such as the Navier-Stokes-Fourrier set of equations fail to describe flows of these regimes. We present a Direct Simulation Monte Carlo study of a 3D porous structure in an unlimited parallel simulation. The three-dimensional geometry was obtained using a microcomputed-tomography (micro-CT) scanner with a resolution in the scale of some m. The gas considered is CH 4 (100%) and the gas inter-molecular collision model for the simulation is the variable hard sphere (VHS). We present results for different Knudsen numbers. The DSMC is applied in porous structures for the flow regimes where it was found in the cavity case to be appropriate. Our results demonstrate that significant differences appear in gas properties depending on the Knudsen number and the flow regime. pure hydrodynamic regime [9]. It is well accepted that the breakdown of the NSF can be quantified by the general criterion of Alexander et. al [10].Shale gas reservoirs have pressures near some MPa. The mean free path () is comparable to the characteristic length of the pore and the gas is often in rarefied regime [11,12]. The ratio of the mean free path to the characteristic length of the flow domain (pore size) is the Knudsen number.Computer simulations are widely used in our days due to the expansion and capability of personal computers and the use of High Performance Computers (H.P.C). Their relatively low cost and their ability to deliver data that is not easily obtained through experiment in lab made them extensively attractive. Simulation for reservoir modeling and transport through porous media become increasingly important in order to optimize and improve gas recovery [13].
A hybrid natural fractured reservoir static geomodel using a wide range of 2D/3D seismic, geometrical and petrophysical attributes has enabled a reasonable 3D representation of three sets of fractures in the SA field, part of North Kuwait Jurassic Complex (NKJC). Based on well and seismic data, the three sets are fracture corridors associated with geophysically interpreted faults; medium scale layer-bound geomechanically controlled fractures; and folding-related fractures. The new hybrid fracture model, which is made of a discrete fracture network (DFN) and an implict fracture model (IFM), was calibrated using production logging tool (PLT), modular formation dynamics tester (MDT), and pressure buildup (PBU) data from 27 wells. The calibrated hybrid fracture model has shortened the process of the history match significantly, requiring only very small adjustments/alterations to the initial static model. Achieving a smooth and timely history match resulted in significant CPU time gain and an optimized well count that went into the Asset Action Plan.
A project was undertaken to construct an overview to build an integrated asset model (IAM) of an onshore fractured carbonate gas condensate and volatile oil asset in Northern Kuwait that is considered the first gas asset discovered in Kuwait. The asset has the potential to produce from six distributed fields producing from four hydrocarbon-bearing structures. The development strategy calls for extensive drilling and facilities expansion to increase and sustain production with the potential addition of depletion compression to further sustain the plateau. Because the reservoirs are highly compartmentalized, they are split into 19 separate models. Production is through three surface facilities, fluids vary significantly across the field from sour gas condensate to volatile oil, and it is important to consider the impact of reservoir deliverability, facilities capacity, and surface backpressure when evaluating different development scenarios. A novel IAM was constructed that integrates reservoirs, wells, pipelines, and facilities models into an integration platform. The IAM comprises 19 black oil dual porosity reservoir models coupled to a compositional network model via black oil delumping to convert the subsurface rates into six-components composition. A split table (compositional delumping) is then used to convert the six-components composition to 35 surface components to be used in the equation-of-state (EOS) surface network models to estimate the composition at each point at the surface (inlet and outlet of each facility). Then the network model is coupled to surface facilities modeling to estimate the rates and composition at the export level. This idea of mapping the subsurface fluid from black oil at subsurface to compositional at surface reduces the subsurface running time and makes the IAM more feasible from the running time perspective. The IAM has highlighted several differences versus the stand-alone modeling and the coupled modeling at the surface only. First, more accurate accounting for backpressure results in an increase in the plateau. Second, a production forecast for each facility gives a detailed analysis of production and the number of wells for each facility. Finally, detailed compositional information becomes available at all points in the surface network, which is important input to the facilities design.
With the advances made in drilling long horizontal wells over the past decades it has become economically attractive to produce oil from thin oil rims. However, the production from these types of reservoirs presents several challenges. Gas coning is one of the most important ones. Horizontal well drilling traditionally helps to improve the oil recovery and avoid problems of premature gas/water breakthrough. In Bouri field, offshore Libya, the main concern of the operator was to establish an advanced method of controlling gas and water encroachment in a fractured carbonate reservoir characterized by high vertical permeability. This paper describes the first Inflow Control Device (ICD) installation for Mellitah Oil & Gas, and the first such application in Libya Offshore field. It was an integral part of a well completion aimed at evenly distributing inflow in a horizontal well, and at limiting the negative effects after occurrence of expected gas breakthrough. Due to small clearances involved, the ICD deployment presented a significant operational challenge. Despite the higher initial completion costs associated with ICDs, they can provide a cost-effective way to reduce long-term operating costs and increase yield. Production targets are achieved with longer, but fewer wells, maintenance and overhead. From a reservoir management point of view, ICDs can improve the productivity index (PI) by maximizing reservoir contact, minimizing gas coning by operating at lower drawdown, and increasing overall efficiency .Swellingpackers were used to compartmentalize the horizontal and build sections, allowing better drawdown control and eliminating crossflow issues. The completion required re-thinking of the established acid-wash treatment procedures, ultimately improving the overall well clean-up. Integrated analysis methods using steady-state wellbore hydraulic and 3D dynamic simulators were performed to generate flow profiles and calculate ICD pressure drop along the horizontal section. The models were updated using results from logging-while-drilling (LWD) and with real-time modifications to the initial design. To verify the inflow profile along the length of the ICD completion, production logging (PLT) was conducted. The inflow profiles compared favorably with those predicted by the models.
Horizontal well drilling traditionally helps to improve the oil recovery and avoid problems of premature gas/water breakthrough. In Bouri field, offshore Libya, the main concern of the operator was to establish an advanced method of controlling gas and water encroachment in a fractured carbonate reservoir characterized by high vertical permeability. This paper describes the first Inflow Control Device (ICD) installation for Mellitah Oil & Gas, and the first such application in Libya. It was an integral part of a well completion aimed at evenly distributing inflow in a horizontal well, and at limiting the negative effects after occurrence of expected gas breakthrough. Due to small clearances involved, the ICD deployment presented a significant operational challenge. Swelling-packers were used to compartmentalize the horizontal and build sections, allowing better drawdown control and eliminating cross-flow issues. The completion required re-thinking of the established acid-wash treatment procedures, ultimately improving the overall well clean-up. Integrated analysis methods using steady-state wellbore hydraulic and 3D dynamic simulators were performed to generate flow profiles and calculate ICD pressure drop along the horizontal section. The models were updated using results from logging-while-drilling (LWD) and with real-time modifications to the initial design. To verify the inflow profile along the length of the ICD completion, production logging (PLT) was conducted. The inflow profiles compared favorably with those predicted by the models.
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