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Results
Abstract High permeability fracturing has become a major well completion technique both for production rate increase and, especially, for pressure drawdown decrease. Today, this type of treatment is the main means of sand control in some petroleum regions. Several of these treatments which are characterized by short lengths and, often, disproportionate widths, have been reported to exhibit positive posttreatment skin effects. This can only be the result of fracture face-damage. This paper indicates that if the extent of fracturing fluid invasion is minimized, the degree of damage (i.e., permeability impairment due to filtercake or polymer invasion) is of secondary importance. Thus, if the fluid leakoff penetration is small, even severe permeability impairments can be tolerated without exhibiting positive skin effects. While the first priority in designing fracture treatments should be to maximize the fracture conductivity, it is recommended that in high permeability fracturing, high polymer concentration cross-linked fracturing fluids with fluid loss additives and breakers should be used. Experimental work corroborates these contentions. Introduction High permeability fracturing is now a widespread well completion technique. This two-step-in-one fracture stimulation and gravel pack procedure allows for increased production rates with very effective sand control. A tip-screenout (TSO) treatment is used which involves the arrest of lateral fracture propagation, followed by the inflation of the fracture. What is produced is a relatively short fracture with a large width and, especially, a much higher conductivity than what unrestricted fracturing can yield. In higher permeability reservoirs, the fracture conductivity is of primary concern, while the fracture length is of secondary importance. A smaller fracture length limits the fracturing fluid leakoff into high permeability reservoirs, which is crucial to the success of the treatment as will be demonstrated below. Fracturing fluids for high permeability applications have included both linear gels, such as hydroxyethylcellulose (HEC), influenced by their wide use in conventional gravel packing, and crosslinked gels (HPG and derivatives) prominent in conventional hydraulic fracturing. Linear gels have been known to penetrate cores of very low permeability (1 md or less) whereas crosslinked polymers are likely to build filtercakes at permeabilities at least two orders of magnitude higher. Clearly, filtercakes, although they may damage the fracture face considerably, reduce the extent of polymer solution penetration into the reservoir, normal to the fracture path. However, at much higher permeabilities, even cross-linked polymer solutions may invade the formation, causing fracture-face damage. (Note: the term fracture-face damage does not mean only damage at the fracture face but includes all leakoff-induced permeability impairments caused by the filtercake, polymer-invaded and filtercake-invaded zones.) Cinco and co-workers have pioneered the understanding of the performance of finite-conductivity fractures, including the delineation of the three major types of damage affecting this performance. Reduction to the proppant-pack permeability which may result from either proppant crushing or, especially, unbroken polymer chains, would lead to fracture conductivity impairment which would be particularly problematic in moderate to high permeability reservoirs. Steps have been taken to reduce, or even eliminate this effect by extensive research in breaker technology. Choke damage refers to the near-well zone of the fracture which can be accounted for by a skin effect. This damage can result from either overdisplacement at the end of a treatment or by fines migration (native or proppant) during production and their accumulation near the well but within the fracture. P. 281
SPE Members Abstract "Wormholes", which are characteristic shapes resulting from the acidizing of carbonate formations have been considered in the past as fractals. In previous publications, analytical relationships of the area penetrated by wormholes, the wormhole porosity and the fractal dimension have been presented. Local mineral compositional heterogeneities and structures result in uneven reaction profiles when acid reacts with carbonate rocks. This, coupled with permeability heterogeneities, leads to microscopic flow instabilities which may evolve into macroscopic wormhole patterns. The understanding of the physics of acidizing is becoming a serious issue with the emergence of horizontal wells, where massive volumes of acid may be needed for effective stimulation. The stochastic nature of the wormholing process has been a limiting factor for a physical interpretation. The simulation of this unstable growth process is the purpose of this paper. The impacts of permeability anisotropy, heterogeneous distribution of the properties of the formation, such as microfractures and zones of different permeabilities, are investigated. A simulation model, the permeability driven fingering model (PDF) is presented. This technique is a new approach to diffusion limited growth, which traditionally has been simulated with diffusion limited aggregation models (DLA). The randomness of fractal growth is changed by introducing a bias representing the permeability anisotropy and the preferential reaction kinetics of lithologic heterogeneities. Introduction The formation of wormholes in carbonate acidizing is driven by a dynamic fluid instability which is conceptually similar to what is known as viscous finger instability. The physical difference of wormhole growth is that the instability is caused by a discontinuous jump in the permeability between the untreated matrix and the highly conductive paths of the wormhole network. In viscous fingering it is the difference between the viscosity of the displacing and displaced fluids which causes the growth of small perturbations to the two-fluid interface. In the case of the wormhole instability (later referred to as permeability fingering, in contrast to viscous fingering) the viscosity ratio between injection fluid and the reservoir fluids is close to one, especially if an acid pre-flush is considered. Therefore, viscosity will not be the primary driving force for the instability in the injection front which leads to wormhole growth. The striking similarity between how a viscosity ratio and permeability ratio cause a fingering pattern to develop has encouraged us to apply a similar model based on stochastic growth. In this paper we will describe the permeability driven fingering model (PDF) which is an extension of the dielectric breakdown model with tunable noise. P. 413^
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Production From Heavy Gas Condensate Reservoirs
Cvetkovic, B. (INA-Neftaplin) | Economides, M.J. (Mining U. Leoben) | Omrcen, B. (INA-Naftaplin) | Longaric, B. (INA-Naftaplin)
Abstract heavy gas condensate reservoirs (>0.75) present interesting challenges in their study, production and reservoir management. Simulation and history matching are often hindered by the lack of appropriate PVT properties. Furthermore, it is well established that they experience properties. Furthermore, it is well established that they experience hysteresis effects following a shutin. Remedial action is cumbersome but possible. This work presents a simulation of the behavior of both lean and possible. This work presents a simulation of the behavior of both lean and heavy (rich) gas condensate reservoirs, shows radial liquid profiles for various flowing bottomhole pressures (compared with a phase diagram), demonstrates degree of gas relative permeability reduction and explains the hysteresis effect. Lean gas injection is a remedial action, reducing the near-wellbore liquid saturation. The study shows that the degree of the adverse gas relative permeability reduction can be minimized or tempered by the appropriate choice of the flowing bottomhole pressure, ie., production can be optimized. Introduction The producing rate of gas condensate reservoirs is affected greatly by the flowing bottomhole pressure and not only because of the pressure gradient in the reservoir. The value of the bottomhole pressure controls the amount and distribution of liquid condensate accumulation near the well with an unavoidable relative permeability reduction. The higher the gas gravity, the more the liquid condensate will be and therefore the relative permeability-to gas reduction will be more pronounced. The classification permeability-to gas reduction will be more pronounced. The classification of lean and heavy (rich) gas condensate has been presented by Cronquist. A separation between the gas condensate region and the volatile oil region appears to be at 11% heptane-plus. Figure 1 contains the initial condition of two reservoir fluids from two different fields that are studied in this paper. One of these is well within the lean gas condensate region where the paper. One of these is well within the lean gas condensate region where the second is very near the volatile oil line. This fluid can be readily classified as a heavy (rich) gas condensate. Fussell in a frequently referenced paper has stated "productivity (from gas condensate producing wells) is severely curtailed when the flowing bottomhole pressure is less than the saturation pressure of the in-place fluid." While this contention is true, the implication that gas condensate reservoirs can be produced with a bottomhole pressure above the dew point pressure produced with a bottomhole pressure above the dew point pressure ("saturation pressure" in Fussell's nomenclature) is rarely, if ever, feasible. A survey of several gas condensate reservoirs has shown that invariably, the initial reservoir pressure is at, or very near, the dew point pressure. As a consequence, to have any appreciable driving force in the reservoir, production from gas condensate reservoirs should be the result of an production from gas condensate reservoirs should be the result of an optimization of (1) The producing rate and the reservoir pressure in Eq. 1 are, of course, time functions while the relative permeability to gas, krg, is a function of both space and time. Therefore, to maximize the cumulative production within any time period (transient, steady state or pseudosteady production within any time period (transient, steady state or pseudosteady state) it is necessary to attempt a number of simulations ahead of time. This must be augmented by laboratory-determined relative permeability curves. There exists an optimum flowing bottomhole pressure for a given average reservoir pressure and operational constraints, that would result in a relative permeability reduction distributed in the reservoir and especially around the well, such that the product (P -Pwf) : krg is maximized. The bottomhole pressure "path", ie., its evolution with time is very important. Once condensate is formed near the well, very little can revaporize into the gas phase even if the pressure is built up to the original reservoir pressure. Thus, if a condensate well is shut in and then re-opened the production rate of the new flow period will continue largely unaffected by the buildup. P. 471