The expandable openhole liner system is used as solution for operational challenges associated with borehole instabilities, pore pressure/fracture gradient issues and the effect of salt or subsalt formation. All these operational challenges produce premature downsizing of well's tubular. While drilling in the Kupal oilfield located in south west of Ahwaz, Iran, an isolated extreme thief zone was penetrated resulting in a possible unplanned conventional liner was run, decreasing further deeper hole sizes. The smaller size of liner would have cause problems such as lower reservoir production rate and putting limitations on running measurement tools to evaluate the reservoir. Because of these aforementioned negative effects of running a conventional liner it was instead desided to run an expandable openhole liner. This paper discusses challenges and solutions for running the first expandable openhole liner in Iran to reach a proposed target with the planned hole sizes as well as a cost evaluation and comparison of two wells, one using expandable open hole liner and one using conventional liner. Introduction The Kupal oilfield is located 50 km south west of Ahwaz, Iran. It is divided in two parts: East Kupal and West Kupal. This field was discovered in 1955. The Kupal oilfied formations are Agha Jari, Mishan, Gachsaran, Asmari, Pabdeh, Gurpi, Ilam, Sarvak, Kazhdumi, Khami, Dariyan, Gadvan, and Fahliyan. Table 1 shows a brief review of the formations in this oilfield. It was found that to reach the proposed target and the needed reservoir hole size in this oilfield using expandable openhole liner is the best solution. The expandable tubular technology concept is basically cold-working of the steel down hole. A mandrel, pig or expander is used to permanently mechanically deform the pipe as shown in Figure 1. The pig is activated either by pressure across the pig itself or by a direct pull or push force, deforming the pipe's metal into its plastic region, illustrated in Figure 2. Typically, expansions as high as 25% can be achieved based on the diameter of the pipe. Most applications use tubulars from 3½" to 16" and these typically require less than a 25% expansion. Multitudes of applications exist for this technology. One of these is the Expandable Openhole Liner (EOL) system, which is used to solve lost circulation problems and sealing off trouble zones, such as those encountered in sub-salt rubble zones, or in zones where the pore pressure/fracture gradient relationship is troublesome. The EOL system provides effective cost-saving solutions for many planned and contingency openhole operations by giving operators an extra casing string. Increased casing length with negligible reduction in diameter can be very applicable, especially in operations that have intensive casing programs in the upper hole section, which else would not have had a cost effective solution. It can actually give the operator two casing strings for the cost of one hole size in a normal conventional casing program.
This paper evaluates and compares current multifractured horizontal well inflow models for possible use in a nodal analysis fractured horizontal well simulator. Nine different inflow models have been proposed for vertical hydraulic fractures intersecting a horizontal wellbore The fracture inflow model types consist of analytical and numerical models which assume either uniform flux, infinite conductivity and finite conductivity fractures. This paper discusses these models. Soliman et al. and others have presented numerical results of a horizontal well intersecting vertical fractures, which creates radial flow within fracture. Modifications are suggested to the current linear fracture flow models used in the three fracture inflow model types mentioned above. One of the types uses a limited communication term proposed by Schulte and another uses a skin effect introduced by Mukherjee and Economides. The results of this study suggest the best inflow equations for various assumed fractured horizontal well scenarios. Introduction Fracturing horizontal well in reservoir that commonly fracture stimulated when drilled vertically may further improve well productivity. But there are particular situations where fracturing a horizontal well is an economically attractive completion option. It may take place under several scenarios, some of which are low vertical permeability, presence of shale streaks, low formation permeability, small stress contrast between pay zone and adjacent layers. A complete understanding of the in situ stress is essential before the well is drilled because of the dependence of fracture orientation of well direction with respect to the stress field. At depths usually encountered in the oilfield >1500 ft) an induced fracture may normally be assumed to be vertical and perpendicular to the minimum horizontal stress. There are two distinct directions the wellbore can be drilled to enhance fracturing operations. If the horizontal well is drilled in the direction of the least horizontal stress, several vertical fractures may be spaced along its axis wherever perforations are located. This spacing is one of the design parameters to be selected. By changing the wellbore azimuth by 900 and drilling normal to the least stress, fracture will propagate along the wellbore resulting in longitudinal fracture. When the wellbore is not in one of these two major directions, several scenarios may occur, depending on the angle between the borehole and the stress direction and on the perforation distribution and density. In this paper only the presence of fractures perpendicular to the horizontal wellbore is discussed. The effect of hydraulic fracture on pressure behavior has been investigated in great detail since early 60s. Prats et al. discussed the performance of vertically fractured wells for the cases of incompressible as well as compressible field. Russell and Truitt solved the pressure behavior of an infinite conductivity vertical fracture by means of finite difference method. Since then, three different models have been proposed for vertical hydraulically fractured wells. They are uniform flux fracture, infinite conductivity fracture, and finite conductivity fracture. The analytical solution for the uniform flux fracture model was developed by Gringarten et al. The assumption they made is that the flow rate per unit length of fracture is constant along its entire fracture. The infinite conductivity fracture model, also contributed by Gringarten et al. assumes that the fluid entry flux along the fracture caused a constant pressure along the fracture. The analytical expression for the pressure distribution created by the plane vertical fracture may be obtained by the Green's function and product solution method using appropriate source functions presented by Gringarten and Ramey. The weakness of these two models to exemplify nonideality led to the solution for finite conductivity fractures by Cinco-Ley et al.
The application of managed pressure drilling (MPD) is becoming more widely spread throughout the world. It is well known that MPD has less hydrostatic head during drilling therefore the rate of penetration (ROP) is increased. This is due to the reduced rock confinement and chip hold down effects. By simulating the conventional drilling and MPD of a well in advance the benefits of MPD can be quantified in terms of increase in ROP and therefore the economical benefits. Applying a commercially available drilling simulator (1)meter by meter drilling performance is analyzed, first simulating and optimizing a conventional drilling operation and then performing the same procedure for a MPD operation in Western Canada. The additional costs of the MPD operation are integrated into the economical analysis. The analysis shows that the ROP during MPD in the higher mud weight regime of the well is improved from 60 to 80 percent. In addition to the faster drilling during MPD the drill bits last longer due to the lesser hardness of the rock being less confined and therefore also reducing the amount of bit wear and the number of bits required and tripping time. Overall the results indicate that the MPD operation reduce the drilling cost of gas wells in Central Alberta more then 20 percent and due to the reduced time at the location less environmental impact is seen. Introduction The first objective of this exercise was to develop a "base case" drilling simulation from which subsequent optimization simulations could be run. An apparent rock strength log (ARSL) was developed based on actual drilling data and formed the backbone of all subsequent calculations. The second objective of the exercise was to compare the non-optimized base case (as above) with an optimized base case. Based on previous experience, drilling economics should improve by approximately 25%. The third and primary objective of this exercise was to compare the optimized base case with an optimized Managed Pressure drilling (MPD) case and, if possible, to justify the additional cost of implementing MPD technology.
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