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The productivity of perforated completions situated in either homogeneous reservoirs or zones of permeability damage is described. Calculations for both types of reservoirs require use of a perforation skin factor; calculations for a damaged reservoir additionally require a damage skin factor. Nomograms are presented for calculating these factors. Introduction In perforated completions, fluids enter the wellbore through tunnels made by bullets or jets that penetrate the casing, cement sheath, and part of the producing formation. The productivity of such completions has been studied by various investigators, with either computer models or electrolytic analog models. Harris recently published a series of curves for calculating skin factors published a series of curves for calculating skin factors in terms of predetermined dimensionless well and perforation parameters. These skin factors are used in computing parameters. These skin factors are used in computing the productivity ratio (the productivity of a cased and perforated completion vs that of an equivalent open-hole perforated completion vs that of an equivalent open-hole completion). Harris' graphs, however, are difficult to use because they are based on dimensionless parameters that must be predetermined, and they require extensive extrapolation predetermined, and they require extensive extrapolation for well diameters larger than 6 in. In addition, Harris' model covers only the simple, regular patterns, and requires that the perforations in a horizontal plane be directly above or below those in adjacent planes. Application of Harris' model is also restricted by the assumption that the formation permeability has not been damaged by the normal drilling and perforating processes. processes. The study reported here describes the productivity of perforated completions situated in either homogeneous perforated completions situated in either homogeneous reservoirs or zones of permeability damage. Calculations for both types of reservoirs require use of a perforation skin factor; calculations for a damaged reservoir additionally require a damage skin factor. Nomograms are presented for calculating these factors. presented for calculating these factors. Separate nomograms are provided for the two basically different types of perforation patterns: simple and staggered. In the latter, perforations in a horizontal plane can be 90 degrees or 180 degrees out of phase with those in adjacent horizontal planes (Table 1). Three samples illustrate the use of these nomograms for calculating skin factors and productivity ratios. The effects on productivity of perforation parameters such as size, patterns, penetration, and density are shown by graphs relating them to the productivity ratio. Development of Nomograms Well in a Homogeneous Reservoir The usual relationship of flow rate and pressure drop for quasi steady-state flow is which is for one-dimensional radial flow into an open hole. When flow is into perforations that penetrate the formation, the flow geometry takes on three-dimensional aspects. The difference in pressure drop between convergent flow to perforations and radial now to an open hole is the basis for the perforation skin factor, Sp. This factor is used in a similar radial flow equation, JPT P. 1027
Summary Using a combination of analytical calculations and 3D finite-element simulation, we have developed a comprehensive skin-factor model for perforated horizontal wells. In this paper, we present the mathematical model development and validation by comparison with finite-element simulation results. With the new perforation skin model, we then show how to optimize horizontal well perforating to maximize well productivity. A cased, perforated well may have lower productivity (as characterized by a positive skin factor) relative to the equivalent openhole completion because of two factors: the convergence of the flow to the perforations, and the blockage of the flow by the wellbore itself. Because of the orientation of a horizontal well relative to the anisotropic permeability field, perforation skin models for vertical wells that consider these effects, notably the Karakas and Tariq model (1991), are not directly applicable to perforated horizontal completions. Using appropriate variable transformations, we derived a skin-factor model for a horizontal perforated completion that is analogous to the Karakas and Tariq (1991) vertical-well model. The empirical parameters in the model were determined from an extensive 3D finite-element simulation study. The results of the new model show that the azimuth of a perforation (the angle between the perforation tunnel and the maximum permeability direction, usually thought to be in the horizontal direction) affects the performance of perforated completions in anisotropic reservoirs. When perforations are normal to the maximum-permeability direction, perforations will enhance horizontal-well flow compared with an openhole completion (a negative skin factor). But if perforations are in the same direction as the maximum permeability, significant positive skin will result. The new skin-factor model provides a clear guide to the shot density, perforation orientation, and level of perforation damage that is tolerable to create high-productivity perforated completions in horizontal wells. Introduction A skin factor can be used to mathematically account for any deviations of the flow and pressure field in the near-well vicinity from perfectly radial flow to a wellbore of radius rw. A perforated completion obviously has a flow and pressure field near the perforations that is not perfectly radial. As shown by Karakas and Tariq (1991), the altered flow characteristics near perforations can be conveniently divided into three parts: the flow in a plane perpendicular to the wellbore, the blockage of flow to the perforations by the wellbore itself, and the fully 3D flow resulting from the asymmetric distribution of perforations along the wellbore. These effects on the near-well flow field and the corresponding perforation skin factor components are illustrated in Fig. 1. Perforation skin models for vertical wells (Karakas and Tariq 1991; Harris 1966; Locke 1981; Klotz et al. 1974) have already been presented in many papers. However, they are not directly applicable to a horizontal well because the reservoir anisotropy in a horizontal well creates complex plane-flow geometry normal to the well, which alters the flow efficiency of a perforated completion. In this work, we present a new skin-factor model developed for a cased, perforated horizontal well. From our observations, the 2D plane flow skin, s2D, the wellbore blockage skin, swb, and the 3D convergence skin, s3D, greatly depend on the magnitude of the permeability anisotropy and the perforation angle measured from a horizontal plane. Our model is based on the conventional perforation skin model for a vertical well presented by Karakas and Tariq (1991). Our perforation skin model is a semianalytical solution that is correlated with numerical simulation results. The reliability of any empirical correlation for perforation skin factors will depend on the accuracy of the numerical simulations. The finite-element method (FEM), which is suitable for complex flow geometry problems, has been widely applied by many authors (Karakas and Tariq 1991; Klotz et al. 1974). In this study, we used the FEM to numerically model the performance of perforated horizontal wells. Our model uses an automatic and adaptive mesh generation program, GID (CIMNE 2006), to generate the finite-element grid. One of the great advantages of introducing a skin model for a perforated well is that it can be easily incorporated into any existing model of reservoir inflow performance or into a reservoir simulator. The modified perforation skin model developed here gives optimized perforation conditions and helps us to understand complex flow geometry in a horizontal perforated well. Using an accurate finite-element simulator, we also show a verification of the model.
Abstract Donggi Structure is one of the gas field prospected in Banggai Basin, Central Sulawesi. Donggi-1 (DNG-1), which is the first well drill in this field, was drilled in August 14, 2001 and was reached TD at 2498.5 m. The drilling in this well has been successfully done without any major problem and it is ± 2 day finished ahead of drilling prediction/program. Donggi gas field is commonly composed of Carbonate reef (limestone). The lithology of this field sequence from surface down to basement is : Celebes Molase, followed by POH formation (clay with sandstone), Mentawa member (reef of limestone), Minahaki formation (limestone) and Tomori formation (limestone). To prove the gas prone seeing from logging evaluation after drilling, TCP gun was run by using "Extreme Underbalance Perforation" technique to perforate the well completed with the DST assembly. The gun system is a mechanical release that secures the guns firmly during perforation and avoiding the risk of fishing the tool after the operation. The well is flowing immediately after the perforation which will allow immediate well clean up. Therefore, the well productivity will increase and formation damage will be minimized. In EUB perforation, it is created more than 1000's psi drawdown instead of less than 100's psi in classical perforation. The EUB application in this well has been successfully flown the gas and condensate during the test and reduced the skin effect and increase the reservoir productivity. It can be seen from the DST-4 and DST-5 analysis result that the skin factor is negative. The isochronal and pressure build up analysis result in zone-4 is Pr = 2560 Psia, AOFP = 25.1 MMSCFD, skin factor is –1.88 and the radius of investigation is 206 m, and in zone-5 is : Pr = 2540 Psia, skin factor is - 4.42, and the radius of investigation is 1593 m. Introduction Donggi well # 1 (DNG-1) is the first exploration well in Donggi field. This well was drilled in the centre of the Donggi closure. Donggi field is located 50 km westward of Senoro-1 discovered well in Banggai province, Central Sulawesi. The well is spuded in on 14 August 2001 and reaches depth at 2498.5 mss on 4 September 2001. Five interval of perforation then tested by running DST. DST-1,2,3 is dry and the last two intervals have tested as a proven gas formation. Extreme Underbalance Perforation Nowadays underbalance perforation has been most widely accepted / applied in oil / gas wells completion, especially in development wells. Several experiments have been performed in order to optimize perforation result. In general, there are four key aspects to perforating that play an important role in determining the productivity : perforation dimensions (length and diameter), shot density, phasing and perforation damage. Single shot perforating / flow experiment has provided a basic understanding of perforation damage and underbalance cleanup. Although turbulent flow does occur at very early times with low viscosity fluids, it is not considered the dominant factor affecting cleanup. Two forces are considered : The first is the pressure differential across a particle during gradient. The second is the subsequent transient, weakly compressible radial flow (laminar or turbulent).
Abstract Wellbore completions are a key well component and could have a positive or a negative impact on productivity, thus designing a suitable completion and implementing it properly must be a priority for production engineers. Consequently, well productivity indices related to specific completion designs have received much attention in the literature, with analytical and numerical models used for simulating various completion properties. The completion impact on wellbore skin effect, however, is seldom documented. This paper looks at the effect of completion and reservoir characteristics on skin factors, and focuses on perforated, gravel-packed and frac-packed wells. For this study, a commercial black oil simulator was used to simulate different reservoir conditions and completion strategies, and the resulting skin effects were estimated by well test analysis of the corresponding synthetic pressure and rate data. Results show that decreasing perforation density and tunnel length leads to high skin values due to wellbore flow restrictions. Moreover, it shows how a damaged gravel-pack completion coupled with a highly permeable formation results in high skin values that range between 1 and 100. Finally, in frac-pack completions, it is important to find the right balance between formation permeability and proppant permeability in the fracture as well as the permeability contrast between the proppant and the gravel as this dictates how a frac-pack will perform. Thus, depending on permeability of proppant and gravel-pack, skin values for frac-pack completions range between -2.5 to 15
Summary Drilling and completing long horizontal wells in North Sea oil fields is extremely costly. When perforating these long horizontal sections (1000 m), deployment of the perforation guns on drillpipe has been regarded as the safest and most cost-efficient method. The well is then kept in overbalance until the completion is installed. To maintain well control, a fluid with loss-control capability [kill pill (KP)] is used as completion fluid during perforating to seal the formation immediately after perforating. This saves the time required to displace completion brine and the cost of losing the expensive brine into the formation. However, perforating with the kill fluid in the wellbore presents a great challenge in minimizing formation damage. Therefore, optimizing the perforating design and choosing the proper kill fluid are crucial tasks to ensure good well productivity. A thorough laboratory testing program has been performed to re-evaluate perforating strategy and completion-fluids selection for several fields in the North Sea. The fluid systems investigated include oil-based mud and water-based KPs formulated from formates and bromide brines. The laboratory results have shown that if the perforating is designed and executed properly, formation damage can be reduced to a minimum even during overbalanced perforating. In this work, the major damage appears to be from the kill fluids. When using a water-based KP, the reduction in relative permeability appears to be an important damage mechanism. Therefore, the productivity is influenced strongly by the fluid-loss-control capability. In contrast, filtrate invasion from the oil-based mud does not alter relative permeability; therefore, the formation damage shown in these tests is less pronounced. Furthermore, zinc- and steel-cased charges have been used to investigate their compatibility with kill fluids and their impact on formation damage. These studies have shown that interaction between zinc and CaBr2-based KPs can cause failure of fluid-loss control and excessive invasion of filtrate, leading to severe productivity impairment. This paper presents some of the results of the laboratory testing program. Introduction Completing a horizontal well in a hostile environment such as the North Sea is a complex and costly operation. To reduce risk and cost, Hydro has (for some fields) practiced overbalanced perforating. A perforation fluid containing viscosifier and fluid-loss-control material is spotted across the reservoir section before perforating. A filter cake is created immediately after detonation to minimize fluid loss and formation damage. The well is then shut in with the kill fluid in place for several days while the remaining completion is installed. The perforation fluid is optimized for the specific field or well; however, brines containing bridging material and polymers are most often used. The type of brine is selected on the basis of the specific gravity requirement and the formation-damage potential. In this work, perforating fluids based on heavy brines such as KCOOH, CsCOOH, and CaBr2 are presented. Oil-based-fluid systems also are investigated. Zinc-cased shaped charges have been used to perforate long horizontal wells because zinc shatters into fine powder-like perforating debris, which is easy to mobilize and produce out of the well. If necessary, the debris can be removed by an acid treatment, although this is not standard practice for Hydro. It is assumed that little perforation debris remains in the well after cleanup, and the risk of obstruction for future well interventions is therefore minimized. However, it has been observed in the past that the zinc-charge debris could react with a calcium-containing water-based fluid to form precipitants and cause problems in well-completion operations. Concerns were also raised that these precipitants might severely plug the formation around the perforation tunnel. Minimizing perforation damage requires proper design of the perforating job. There have been many studies conducted to optimize perforating design with completion brine in the wellbore. Most concluded that underbalanced perforating is necessary to prevent high perforation skin. Recently, new studies have shown that transient underbalance plays a more important role in perforation cleanup than static underbalance. This transient underbalance can be generated even in overbalanced perforating if carefully designed. In this paper, the additional challenge is to optimize overbalanced perforating with a drilling mud or KP in the wellbore. An extensive study was conducted to characterize formation damage caused by various drilling fluids and KPs when used in overbalanced perforating. The experiments were designed to closely simulate field conditions when perforating overbalanced in a well open to the trip tank. Information about the reservoirs, the completions, and the perforating practices for the two fields studied in this test program are given in Table 1. The reservoir parameters such as pore pressure, overburden stress, and bottomhole temperature and the well parameters such as casing diameters and perforating design are incorporated into the experiments. Fluids The careful formulation and quality control of wellbore fluids is important for the field conditions to minimize formation damage. This becomes even more important in a laboratory study in which the wellbore fluid is one of the primary variables and reliability and reproducibility of results are paramount. For this study, all the fluids were formulated, mixed, and quality controlled at the operator's research center in Bergen, Norway, in close collaboration with their supplier of drill-in and completion fluids for North Sea operations. The fluids were shipped in timely batches to the supplier's Houston facility, where a repeat quality control was performed. Once approved, the fluids were forwarded to the experimental test facility for immediate use. Table 2 lists the wellbore fluids used in the perforating experiments. p. 173–180