|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
This article focuses on interpretation of well test data from wells completed in naturally fractured reservoirs. Because of the presence of two distinct types of porous media, the assumption of homogeneous behavior is no longer valid in naturally fractured reservoirs. This article discusses two naturally fractured reservoir models, the physics governing fluid flow in these reservoirs and semilog and type curve analysis techniques for well tests in these reservoirs. Naturally fractured reservoirs are characterized by the presence of two distinct types of porous media: matrix and fracture. Because of the different fluid storage and conductivity characteristics of the matrix and fractures, these reservoirs often are called dual-porosity reservoirs.
Abstract Production of fluids from petroleum reservoirs reduces the pore pressure, increases the net overburden stress, and consequently, reduces the total porosity and permeability of the reservoir rock. This effect is much more significant in low permeability geo-pressured and naturally fractured reservoirs. For well test purpose, the assumption of constant permeability in the diffusivity equation will yield inaccurate estimates of the reservoir properties for any reservoirs in geo-pressured zone. To study the pressure transient behavior in a stress dependent porous media, it is assumed that permeability of the formation is stress dependent. Hence, a new parameter known as the permeability modulus is introduced. In this study, the effect of stress-sensitivity was incorporated by expressing the permeability as an exponential function of pore pressure in the derivation of a three-dimensional diffusivity equation required to describe the flow of fluid for a horizontal well in a naturally fractured reservoir. The matrix-fracture fluid transfer model considered was the pseudo-steady state flow model. Since pragmatic values for the dimensionless permeability modulus ranges between zero and unity, it was possible to apply the theory of perturbation to develop and solve a system of linear boundary value problem subject to an infinite lateral and bounded vertical boundary condition. Applying the Laplace and finite Fourier cosine transform, an approximate analytical solution in Laplace space was obtained which was inverted numerically. Pressure response curves were generated and analyzed for certain vital parameters.
Abstract Naturally fractured reservoirs (NFRs) are the reservoirs with two distinct types of porous media called the fracture and matrix. The pressure behavior of naturally fractured reservoirs is usually studied by using Warren and Root model (Warren and Root, 1963). Warren and Root model assumes that production from the naturally fractured system goes from the matrix to the fracture and thence to wellbore (Warren and Root, 1963). However, this assumption is oversimplified if the contrast between the permeability of matrix system and that of fracture system is not significant. In order to estimate the limits of validity of solutions based on Warren and Root model and to study the behavior of a naturally fractured reservoir when the contrast between the two permeability are not significant, it is necessary to solve the original model proposed by Barenblatt and Zheltov (Chen 1989). But the analytical solutions to this model which were obtained by numerical analysis or numerical inversion are very complex and inconvenient to use (Lu, Zhu and Tiab, 2009). Assuming that both of the matrix and fractures produce directly into the wellbore, a new mathematical model for dual-permeability naturally fractured reservoirs is presented in this paper. Based on our proposed model, it is concluded that there are four stages for the pressure behavior of NFRs; the double-permeability system behave like a reservoir with a constant pressure boundary when the dimensionless time approaches to infinite. The solution procedure proposed in this paper is a fast tool to evaluate a vertical well performance in a dual-permeability naturally fractured reservoir.
Abstract Low to ultra-low permeability tight oil reservoirs have recently become a significant source of hydrocarbon supply in North America, Production and pressure transient analysis of tight oil reservoirs is one of the most difficult problems facing a reservoir researcher because of the extreme complexity inherent in tight formations, To produce oil and gas commercially from tight formations, naturally completed (open-holed) or cased horizontal wells with multi-stage hydraulic fractures are the most popular implementation for completion, and such kind of application is expected to create a complex sequence of flow regimes (Chen and Raghavan, 1997; Clarkson and Pederson, 2010). The proper analysis and identification of presence of flow regimes and sequence of emerging flow regimes are essential for obtaining efficient information about hydraulic fracturing optimization and the tight formation characterization. This paper provides a detailed discussion of numerical method of pressure transient and rate responses for hydraulically fractured horizontal wells in tight formation and compared with analytical (semi-analytical) methods based on the Bakken and Viking Formation in Western Saskatchewan. For Numerical simulated pressure transient responses, a naturally-completed (open-hole) and cased horizontal well with multiple transverse hydraulic fractures in a homogeneous or a sizable natural fracture system are considered. Numerical method for pressure and rate transient analysis is generated by employing a commercial reservoir simulator, CMG IMEX, a 3D finite-difference reservoir simulation package which is widely and popularly accepted by petroleum industry. As noted by many findings, it is shown that fully-filled and regional natural fractures would display various pressure transient characteristics and, hence, considerably affects well production performance. In addition, these conductive, interconnected natural fractures dominate the pressure transient performances of horizontal wells in tight formations even with the presence of hydraulic fractures. Additionally, the simulation runs also indicate that if the reservoir is naturally fractured to some extent, hydraulic fracturing stimulation might not improve productivity significantly, unless a large amount of hydraulic fractures and infinite conductivities can be achieved. To demonstrate the feasibility of numerical simulation models, there is a representative contrast between numerical and analytical (semi-analytical) methods. To demonstrate the feasibility of numerical simulation models, there is a representative contrast between numerical and analytical (semi-analytical) methods.
Abstract Faults and fractures are common features in many well-known reservoirs. In many of these reservoirs, horizontal wells are drilled to intersect a large number of fractures, particularly in low-matrix-permeability formations. In addition, the application of horizontal wells intersecting multiple hydraulic fractures has been widespread to allow shale gas and oil reservoirs, some of which are also naturally fractured, to produce economically. In this paper, we investigate the pressure transient behavior of horizontal wells in continuously and discretely naturally fractured reservoirs (NFR)s using semi-analytical boundary element solutions. These solutions have the advantages of the absence of grids and reduced dimensionality. Furthermore, they provide continuous rather than discrete solutions. The solutions are sufficiently general to be applied to many different well geometries and reservoir geological settings, where the spatial domain may include arbitrary fracture and/or fault distributions with different types of outer boundaries. A number of solutions have been published in the literature for horizontal wells in NFRs using the conventional dual-porosity models that are not applicable to many of these reservoirs. Most of these published solutions ignore the wellbore and the unfractured sections of the horizontal well. Therefore, they cannot capture the true early-time response, such as fracture radial flow. They may also yield incorrect damage skin values. Our solutions take these effects into account. Our solutions can also be applied to shale gas and oil reservoirs without shale-gas transport nonlinearities when the average reservoir pressure is above the desorption pressure. Our solutions for horizontal wells in fractured reservoirs can contain any spatial distribution of finite or infinite conductivity fractures with arbitrary length and orientation. The number and type of fractures (hydraulic or natural) intersecting the wellbore and with each other are not limited in both homogeneous and naturally fractured reservoirs. We present a number of examples to show different flow regimes that a horizontal well with multiple fractures exhibits, and to show that the conventional dual-porosity models simply do not work and can be deceptive. In our solutions, continuous and discrete conductive and nonconductive fractures are treated explicitly. The exact treatment of the uniform wellbore pressure condition, and the inclusion of the wellbore and the unfractured sections of the horizontal well have led to identification of new flow regimes that were not apparent from the existing solutions. Consequently, our solutions capture the true pressure transient behavior of the system, such as fracture radial flow. In this paper, a new classification of wellbore and fracture skin damage is given, and their effects on the pressure transient behavior are investigated. There are many factors that dominate the pressure transient behavior of horizontal wells intersected by multiple hydraulic fractures in naturally fractured reservoirs, such as fracture conductivities, lengths, and distributions, as well as whether or not fractures intersect the wellbore. Diagnostic derivatives plots are presented for a variety of horizontal wells with multiple fractures in homogenous and NFRs. It is shown that these reservoirs exhibit many different flow regimes. A multistage-fractured horizontal well in a very low-permeability shale reservoir example is also presented. Finally, we have presented two field buildup test examples from NFRs
Abstract This paper describes the first known offshore application of distributed horizontal pulse testing. This technique appraises the deliverability of naturally fractured resource, using only a single penetration and Drill Stem Test (DST) string run. Central to the design is the ability to collect near real-time interference data at a known minimum length from a drawdown interval. The pulse test is distributed in that the signal and observation zones can be swapped on demand from surface, acoustically via sleeve. BP successfully applied this technique to two appraisal wells in their 2014 offshore drilling operations. The dual zone DST pulse testing method is a new approach to the appraisal of naturally fractured reservoirs. It was developed to create a real-time interference dataset outwith the active production interval, i.e. within a passive zone. The formation is produced (and rate data are measured) in two spatial locations and across two known length-scales (by swapping the active and passive zones prior to commingling). Pressure diffusivity can thus be calibrated to data measured in two spatial locations of the same reservoir, and not just one, as per a conventional test design, i.e. enabling a history match of the pressure response of two lateral zones from a pulse signal in one. The horizontal aspect is achieved via high-angle well, drilled sub-parallel to unit bedding (Figure 1). With the double staging approach (upper and lower zones), which has been developed for fractured reservoir appraisal studies, three tests were successfully performed in each appraisal well: two partial penetration tests on discrete short intervals (DST#1a, DST#1b), and one final test on a longer interval that included both of the short intervals (DST#1c). Results of this application have demonstrated that pressure diffusivity can be derived from pressure data that are measured simultaneously in two spatial locations, within and outwith an active production interval. This has proved particularly useful for reducing the degrees of freedom in reservoir model identification. The paper concludes that appraisal of naturally fractured reservoir might be sub-optimal in a DST design where drawdown and observation data are limited to a singular inflow zone only. This is the first known application in the industry where one DST run has successfully yielded six unique appraisal data types, gathered simultaneously at both intra/inter zone and commingled length-scales. These data are conventionally not gathered in a single zone design, i.e. without the ability to selectively inflow and monitor pressure in each discrete lateral zone. Consequently this technique has significantly improved the description of both static and dynamic reservoir properties and reduced development uncertainty, all at a relatively low incremental cost.
Europe and Australia have joined the US in expanding recoverable hydrocarbons from unconventional resources, and initial activities are on the rise elsewhere. However, not all wells are producing commercially, and not all hydraulic-fracture stages contribute within the producing wells, suggesting that it is important to target the field's sweet spots when dealing with shale resources. Therefore, unconventional-resource development based on the current concepts of geometric placement of hydraulic-fracture stages may not be appropriate. Although significant advancements in technology for the development of shale gas/oil plays in North America (particularly in the US) have been made in recent years, a number of these shale wells still experience relatively low initial productivity. There are two possible reasons for this: Fracture placement does not intersect the natural fractures in the well, and reservoir quality [i.e., total-organic-carbon (TOC) levels, thermal maturity, and remaining hydrocarbon in the source-rock reservoir] is low or nonexistent at the locations where fracture stages have been placed.
Abstract Most unconventional gas reservoirs are naturally fractured in nature and exhibit dual porosity characteristics. Hydraulic fracturing often alters the reservoir parameters around the wellbore, thus, potentially creating a rubble zone (stimulated reservoir volume-SRV) with distinctly different characteristics when compared to the outer zone. This problem could ideally be approximated as an equivalent flow problem around a horizontal wellbore in a composite naturally fractured domain. The computational package developed in the current study could be used in generating forward solutions for prediction of production transients in hydraulically fractured double porosity reservoirs. Additionally, as a part of an inverse analysis procedure, using relevant dimensionless parameters, it will be possible to characterize the composite naturally fractured reservoirs. A solution to the elliptical flow problem that considers flow into a horizontal wellbore in a truly composite naturally fractured reservoir has been attempted. Mathieu modified functions were used to solve the elliptical flow problem. Stehfest algorithm is used for inversion of the Laplace space solutions back to real time domain. This generated solution is validated with other existing solutions by collapsing it into its subsets given in the literature. Forward solutions are generated for various dimensionless parameters. A graphic user interface (GUI) has been developed to generate production decline curves. The interface elliptical coordinate does have a significant effect on the dual porosity signature of production transients in the case of mobility ratios higher than 10. It is observed that the mobility ratio, diffusivity ratio, storativity ratio, interporosity flow coefficient ratios of the inner, and outer regions exhibit significant effects on the decline curves experienced by this class of reservoirs.
Abstract Non-Darcy flow is an important factor affecting productivity of gas and high production rate oil wells and the analysis of pressure-transient well tests in porous media. The motivation for this study to investigate, validate and extend the Barree-Conway model (BCM) for pressure-transient analysis of wells involving hydraulic fractures and naturally fractured reservoirs. Numerical models based on finite control-volume method were developed according to not only the Forchheimer equation and, for the first time in the literature, but also the Barree-Conway model specifically for pressure-transient analysis of single-phase fluid flow in porous and fractured reservoirs. The developed numerical models are capable of simulating all near wellbore effects coupled with the non-Darcy flow behavior in porous and fractured reservoirs. This study shows that the BCM can be applied, similar to the Forchheimer model, to analyzing and interpreting pressure-transient responses of non-Darcy flow in porous and fractured reservoirs. The BCM predicts similar pressure-transient responses of non-Darcy flow as predicted by the Forchheimer model. The parameter of characteristic length among the BCM model parameters is more sensitive than the minimum permeability. The minimum permeability is only sensitive at low values of characteristic length or at extremely high flow rates. Numerical simulation results indicate that the value of characteristic length must be low for significant effect of non-Darcy flow and it is related to small effective radius. The non-Darcy flow parameters of the BCM may not be all estimated from single-rate tests in single-porosity reservoirs using conventional analysis approaches. However, they can be estimated by a fitting process based on non-linear optimization algorithm incorporated into the numerical model. Type curves generated by the BCM are provided to demonstrate a methodology for analyzing the effect of non-Darcy flow on pressure-transient tests in porous and fractured reservoirs. As application examples, numerical models of non-Darcy flow are used to model and interpret actual field pressure-transient data from high production rate oil wells in Kuwait.