Second EAGE Middle East Tight Gas Reservoirs Workshop

Simultaneous inversion of 3D seismic data was utilized to identify sweet spots within a Permo -Carboniferous clastic reservoir which is identified as a potential basin-centered gas play in Saudi Arabia. Both acoustic and shear impedances resulting from simultaneous inversion were used to generate seismic sections depicting the product of Lame’ parameters (mu,lambda)and density(rho). Sweet spots of porous hydrocarbon bearing clastic reservoirs can be identified in the lambda*rho and mu*rho domains as having relatively low lambda*rho and mu*rho. These inversion results were calibrated with rock physics modeling work.

Knowing fractures orientation is important for the optimal development of fractured reservoirs. In this paper, walkaround Vertical Seismic Profile (VSP) data is used to determine the orientation of fractures in an Ordovician sand channel in northwestern Saudi Arabia. An azimuthal VSP traveltime and amplitude analysis was performed and the directivity results were then correlated with dipole and FMI well log data.

Unconventional reservoirs are becoming important resources for the future as a result of the drop in production from conventional reservoirs. Tight gas reservoirs are an example of unconventional reservoirs which have very low porosity and permeability, and often they typically have large lateral extent. We analyse several Mam Tor siltstone samples as a means to characterise the stress dependence of tight gas reservoirs. Mainly, we study permeability, through loading and unloading cycles using triaxial core holder against very high effective stresses up to 8000 psi. Such loading tests provide ideal conditions for characterising tight gas reservoirs at great depths. We also study the stress sensitivity of partially brine saturated samples whereby stress sensitivity increases as brine saturation increases. We take this analysis further by measuring ultrasonic velocities against effective stress illustrating permeability-velocity relationship. We then substitute dry ultrasonic velocity measurements to get Gassmann predictions and compare it with ultrasonic velocities at various brine saturations. There is no significant increase in P-wave velocity at low brine saturation (less than 50%) compared to the increase in P-wave velocity at high brine saturations (greater than 50%). Consequently, Gassmann predictions fit lab data better at high brine saturations and over estimate velocities at low saturations.

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The integration of microseismic measurements with complex fracture models can provide a much-needed constraint to the interpretation of complex fracture growth. With this constraint we now have a means to include fracture propagation and mass balance into the microseismic to reservoir simulation workflow. In addition, the introduction of complex hydraulic fracture models provides a much more quantitative method to improve fracture treatment designs and completion strategies. The application of complex fracture models is in its infancy and there is still an enormous learning curve before the models can be routinely used to make reliable decisions. However, complex fracture models, when combined with geomechanical models, microseismic measurements, and reservoir simulation can provide a more reliable evaluation of hydraulic fracture characteristics than previously possible. Microseismic data also provides a constraint for subsequent production modeling. This constraint comes in a number of forms, including characterization of natural fractures, calibrating complex hydraulic fracture models, and providing a bound for the reservoir volume contacted by the hydraulic fracture. With a more reliable estimate of the fracture network properties and a calibrated complex fracture model, treatment designs can be improved more systematically, reducing the trial-and-error empirical approach currently employed in shale-gas development.

High-molecular-weight polymer fluids have been used for stimulation for decades. These fluids exhibit exceptional viscosity, proppant transportability, and fluid leak-off control. However, a major drawback of polymer fluids is the amount of polymer residue they leave behind. Polymer residue has been shown to significantly formation damage. Surfactant micellar fluids structured very low-molecular-weight surfactants into elongated micelles have been used for stimulation trying to remove the drawback of polymer fluids. The viscoelastic behavior of these surfactant micellar fluids is believed to be rooted in the overlap and entanglement of elongated micelles which yields both the viscous and elastic characteristics to the fluid. High fluid leak-off and difficult cleanup associated with traditional surfactant micellar fluids have, however, limited their utility in tight gas stimulation applications. Our recent work has shown that the addition of carefully selected inorganic nano-crystals - less than 100 nm – to the new surfactant micellar fluid formulation can overcome the above limitation without negatively effecting the internal breaking mechanisms. This paper will present our recent results that highlight the mechanism of fluid loss control and easy cleanup of this nanoparticle reinforced surfactant micellar fluid system for tight gas stimulation applications.

Understanding the hydraulic characteristics of the matrix frame, natural fractures, and created hydraulic fractures as a function of effective confining stress, is vital to design optimum stimulation treatments, and to predict reservoir performance via reservoir simulation, and to maximize productivity from these challenging reservoirs by following a smart depletion strategy. Critical parameters that are stress dependent in tight gas reservoirs are: matrix absolute and relative permeabilities, capillary pressure, and natural and hydraulic fracture conductivities. An experimental procedure was designed to simulate the reservoir permeability (matrix, natural fractures and induced fractures) reduction as a function of increasing effective stress.Depleting a tight gas reservoir at high pressure should be based on extensive study of how the matrix and natural fractures behave under pressure history. The smart depletion involves two possibilities: 1) maintaining high pressure depletion, 2) injecting non-fuel gas to produce the fuel gas at the required reservoir pressure.