Constant producing pressure solutions that define declining production rates with time for a naturally fractured reservoir are presented. The solutions for the dimensionless flow rate are based on a model presented by Warren and Root. I The model was extended to include constant producing pressure in both infinite and finite systems. The results obtained for a finite no-flow outer boundary are new and surprising. It was found that the flow rate shows a rapid decline initially, becomes nearly constant for a period, and then a final decline in rate takes place.A striking result of the present study is that ignoring the presence of a constant flow rate period in a type-curve match can lead to erroneous estimates of the dimensionless outer radius of a reservoir. An example is presented to illustrate the method of typecurve matching for a naturally fractured system.

In this paper, based on our analytical model, we analyze the transient pressure response of a naturally fractured reservoir with pressure dependent rock properties. ABSTRACTThe most commonly used methods to describe the transient flow behavior in porous media are based on the assumption of constant rock properties. Nevertheless, these methods are not strictly applicable to reservoirs that undergo changes in the rock properties due to variation in pore pressure. A frequent characteristic of fractured reservoirs is sensitivity of permeability and porosity to effective stress. This paper presents a new analytical model, for interpreting pressure transient test. The model considers the flow in a naturally fractured stress sensitive reservoir, that is to say, the dependency of rock properties on pressure is established (dependency of permeability on pore pressure is measured by the permeability modulus parameter), and makes that the flow equation be strongly non linear. Likewise, the theory is developed under unsteady-state or pseudosteady-state conditions, and considers that: the fracture is uniformly distributed, matrix geometry is the so called stratum and flow contribution from the matrix to the fracture is described by the term source proposed by De Swaan.The problem stated is solved through an analytical approach for different boundary conditions and different permeability modulus values, thus obtaining type curves that can be used for the analysis of pressure buildup and drawdown tests.

Summary Laboratory measurements of compressional (P) and shear (S) wave velocities and first-arrival amplitudes at ultrasonic frequencies (0.65 to 1.70 MHz [0.65 × 106 to 1.70X 106 cycles/sec]) in unconsolidated tar and heavy-oil sands indicate that wave-propagation properties in these materials are sensitive to bitumen content. Studies made at elevated temperatures, overburden pressures, and pore pressures revealed that heat and oil content in Venezuelan, Californian, and Canadian reservoir samples had large effects on the measured P and S velocities and amplitudes. Similar results were obtained on well-consolidated sandstones at lower frequencies (1.60 to 3.60 kHz [1.60x 103 to 3.60 × 10 3 cycles/sec]). The velocity and relative P-wave attenuation results show that in reservoir sands with high brine-to-oil ratios, the presence of steam or gas is easily detected. In sands with low brine-to-oil ratios, with oil occupying at least half of the available pore space, the presence of steam is not easily detected, but velocities and attenuation are highly sensitive to the temperature of heated oil. Indeed, measurable seismic properties may become a powerful tool for mapping temperature distribution, and therefore viscosity distribution, within heated reservoirs. The results suggest that seismic wave transmission and possibly reflection methods should be highly successful in locating thermal EOR fronts and in monitoring the distribution of heated tar and heavy oils within a reservoir. The application for this technique is evident: because of the potential to track heated oil remotely, field operators may be able to potential to track heated oil remotely, field operators may be able to determine optimal placement of future production or injection wells. Introduction An extensive, systematic laboratory study was undertaken to evaluate the application of seismic imaging to the mapping of thermal EOR fronts in unconsolidated sand reservoirs. The study was prompted by known effects of steam or gas on wave propagation in consolidated and unconsolidated rocks, by the successful use of seismic reflection to image steam pods at the Street Ranch and the Saner Ranch pilot projects, and by anticipated but unverified seismically detectable changes in oil viscosity and dynamic bulk compressibility and rigidity upon heating of reservoir sands. The paper summarizes the results of a series of experiments on the effects of elevated overburden pressure, pore pressure, temperature, and oil/brine ratio on pressure, temperature, and oil/brine ratio on ultrasonic-frequency pulse-transmission data. Reservoir samples from three locations were studied:a Venezuelan sand from a heavy-oil field on the eastern coast of Lake Maracaibo,a Californian sand from the Kern River area, anda Canadian sample of Athabasca tar sand. The results were used as experimental controls to assess the applicability of seismic transmission and reflection imaging in a thermal EOR pilot project. Magnitudes of laboratory-determined wave-property changes. the intrinsic resolution of transmission and reflection seismic methods, depth and thickness of the target zone, the scale of heterogeneities within the zone of interest, thermal conductivity of the reservoir sand, and the injection rate of steam are all inputs into the seismic forward model. Modeling permits optimization of observation-well spacings with respect to the injector well, signal strength required of the seismic source, and distance between receiver stations; it also permits assessment of expected signal-to-noise ratios, the frequency band of received signals, and the magnitude of changes in seismic properties expected in a specific field test site. In short, forward modeling is used to design the geometry of the field monitoring system.

Even though the over all performanceof the project is consideredto be good, more informationis needed A study was made to determinethe burned volume regarding the reservoir properties and firefront and the location of the firefront in the Miga P2,3

An analytical model is presented which describes the pressure behaviour of a well completed in a reservoir wherein natural fractures occur over a limited area around the wellbore. The flow in the reservoir is treated as a composite reservoir flow problem, the region adjacent to the wellbore being considered as a fractured medium and the outer region as an homogeneous one. Wellbore storage and skin effects are included in the solution, and the flow in the fractured region is mathematically described by Warren and Root's double porosity theory. Dimensionless log-log plots of pressure vs time show the existence of several well-defined flow regimes, which can be used in the interpretation of pressure transient tests data to estimate the fractured region parameters as well as its radius around the well. This last parameter is of considerable importance for the purposes of reservoir development or infill drilling programs, for it would allow the reservoir engineer to estimate the areal extension of the fractures in the reservoir. Based on the model results for different values of the parameters involved, guidelines are provided for conducting and interpreting a pressure test with the objective of determining the characteristics and areal extent of a natural fracture system. Introduction Due to the large hydrocarbon reserves held by naturally fractured reservoirs, their explotation has become a challenging task for the petroleum industry. Estimation of fracture parameters such as fracture volume, directional trends, storage capacity, etc. are of vital importance for the proper design of explotation strategies. In the past 25 years, a considerable theoretical effort has been made to describe the behaviour of these reservoirs. Based on the work done by Barenblatt, Warren and Root proposed an analytical solution which has been used successfully to describe the transient pressure behaviour of a naturally fractured reservoir. Crawford et al presented field data with no wellbore storage, Sup porting the validity of the Warren and Root model. Mavor compared the Warren and Root's solution with other models and concluded that, from an engineering standpoint, it was the most practical. Also, he extended their work to account for wellbore storage and skin effects. Recently, Da Prat, et al. and Benson and Lai have applied the Warren and Root model to the interpretation of field data with apparent success, indicating the model's practical usefulness. In essence, Warren and Root idealized the fractured reservoir as two distinct systems: matrix and fractures (see Fig. 1). The flow towards a fully penetrating well is assumed to occur only through the fractures. Both the cases of an infinite and a closed reservoir have been treated extensively by the authors mentioned and others. However, to the authors' knowledge, the case of a well completed in a reservoir where natural fractures occur only over a limited area has not been modeled. Such a reservoir situation may be idealized as a composite reservoir model (see Fig. 2) where the inner region adjacent to the well is considered as a radial naturally fractured zone that behaves as proposed by Warren and Root, and an outer radial homogeneous reservoir of either infinite or finite extension. Composite reservoir problems have been the subject of considerable attention in the petroleum literature over the last 25 years. In general, the composite model consists of a well completed in the center of a circular inner region with fluid and rock properties different from those in an outer region. P. 35^