A novel correlation identifying inefficient drilling conditions is presented using experimental and field data. Historically, Mechanical Specific Energy (MSE) has been used to improve the drilling performance with mixed results. Drilling Specific Energy (DSE) is the amount of energy required to destroy and remove underneath the bit a unit volume of rock. DSE includes axial, torsional and hydraulic energy. DSE is different than MSE because it includes a hydraulic term. The initial MSE correlation (Teale, 1964) has been modified to accommodate the new hydraulic term. Experimental and field data presented on the paper show that DSE can be used to identify inefficient drilling conditions. Experimental results illuminate the importance of including bit hydraulics into the specific energy analysis for drilling optimization. Field results reveal specific patterns for inefficient drilling conditions such as; bit balling and friction limited wells. These field results also enligthen a good correlation between the calculated DSE and the rock compressive strength. The novel correlation presented in this paper will help to improve the drilling efficiency worldwide. The new hydraulic term included on the specific energy correlation is the key to correctly matching the amount of energy used to drill and the rock compressive strength. Also, this new term illuminates how much hydraulic energy is needed to drill faster and efficiently when the mechanical energy (axial and torsional) is increased.

Theoretical study, reported in this paper, qualifies unique mechanisms of water coning in gas wells. Water coning in gas wells has been understood as a phenomenon similar to that in the oil wells. It is shown, however that both the water inflow mechanism and its impact on well's productivity are substantially different. It is shown, for example, that, after water breakthrough, the oil-water interface at the well's completion would continue to cone, while the gas-water interface reverses at the top of the cone. Analyzed in the paper are the results of a conventional simulation of water coning in gas wells showing that water could affect productivity only at the very late stage of well's life. However, field data, shown in the paper, evidence early and severe water problems. This contradiction is explained in the paper by including the effects of Non-Darcy flow, perforation density and the ratio of vertical-to-horizontal permeability in modeling of water coning in gas wells. Results from numerical simulation combined with analytical models show that an early water breakthrough and a considerable increase in water production may result from combined effects of increased vertical permeability, lower density of perforation and high-velocity gas flow around the wells. Introduction Water coning in gas well has been understood as a phenomenon similar to that in oil well. In contrast to oil wells, relatively few studies has been reported an aspect of mechanisms of water coning in gas wells. Muskat1 believed that physical mechanism of water coning in gas wells is identical to that for oil wells; moreover, he said that water coning would be less serious difficulties for wells producing from gas zone than for wells producing oil. Trimble and DeRose2 supported Muskat theory with water coning data and simulation for Todhunters Lake Gas field. They calculated water-free production rate using Muskat-Wyckof3 model for oil wells in conjunction with the graph presented by Arthurs4 for coning in homogeneous oil sand. The results were comparing with a field study with a commercial numerical simulator showing that the rates calculated with Muskat-Wyckof3 theory were 0.7 to 0.8 those of the coning model for a 1-year period. Kabir5 used the analogy between high oil mobility well and a typical gas well, to investigate gas well performance coning water in bottom-water drive reservoir. He built a numerical simulator model for a gas-water system. He concluded that permeability and pay thickness are the most important variables governing coning phenomenon. Other variables such as penetration ratio, horizontal to vertical permeability, well spacing, producing rate, and the impermeable shale barrier have very little influence on both the water-gas ratio response and the ultimate recovery. McMullan and Bassioni(6) believed that water coning behaves differently in gas wells than in the oil wells. Using a commercial numerical simulator they got similar results than Kabir(5) for the insensitivity of ultimate gas recovery with variation of perforated interval and production rate. They demonstrated that a well in the bottom water-drive gas reservoir would produce with small water-gas ratio until nearly its entire completion interval is surrender by water. In this study, water problems begin when recovery factor is less than 30%. Fig. 1 shows water-gas ratio and gas recovery factor from field data of a gas well. It shows water production started after 404 days when the recovery was 22%. This well was killed for water production after 600 days of gas production when the recovery factor was 28%. Fig. 2 shows gas and water production rate versus time for another gas well. It shows water production star after 119 days of production. Gas rate was reduced from 6.0 MMSCFD to 4.0 MMSCFD due to water production rate of 30 BPPD. These two field data shows early water production in gas wells.

The paper demonstrates and explains the importance of global inclusion (i.e. throughout the reservoir) of Non-Darcy (N-D) flow component for better prediction of well performance in gas reservoirs with bottom water drive by using a numerical simulator. Traditionally, Non-Darcy flow effect in gas reservoirs has been attributed only to high gas flow rates, and considered locally around the wellbore. Consequently, most numerical simulators have the N-D component assigned to the well rather than distributed throughout the reservoir. Also, the common judgment is that the effect is insignificant at gas rates lower than 10 MMscf/d, so it would not affect gas recovery in the low-rate wells. In this project, we used an analytical model, field data, and a numerical simulator with global and local N-D component to study sensitivity of final recovery and gas rate to N-D flow for a variety of reservoir properties. The results show that disregarding the N-D flow globally leads to overestimation of cumulative gas recovery by up to 42.2 percent. Moreover, this overestimated recovery is the same when N-D is ignored, or assigned locally to the wellbore. It is also shown that N-D effect is significant at low production rates. Shown is the range of reservoir properties where gas wells producing only 9.8 MMscf/D would have total pressure draw-down comprising 70% contribution of N-D flow effect. Introduction Traditionally, the Non-Darcy (N-D) flow effect in a gas reservoir has been associated only with high gas flow rates. Moreover, all petroleum engineering's publications claim that this phenomenon occurs only near the wellbore and is negligible far away from the wellbore. As a result, the N-D flow has not been considered in gas wells producing at rates below 10 MMscf/d, or it has been assigned only to the wellbore skin area. Aditional pressure drop generated by the N-D flow is associated with inertial effects of the fluid flow in porous media.1 Forchheimer2 presented a flow equation including the N-D flow effect as,Equation 1 Where dp/dL=flowing pressure gradient; v=fluid velocity; µ=fluid viscosity; k=formation permeability; ?v2=inertia flow term; and ß= inertia coefficient.2 In deriving an analytical model for ß many authors considered permeability, porosity, and tortuosity the most important factors controlling ß.3–6 Empirical correlations7–12 supported the analytical models, and included rock type as another important factor. Also, liquid saturation was found another important factor. ß increases with water (immobile) saturation.13,14 Experimental studies provided data needed for inclusion of liquid saturation in the equation for inertia coefficient.15–16 Frederic and Graves17 presented three empirical correlations for a wide range of permeability. In the actual wells, (can be calculated from the multi-flow rate tests using Houper's procedure. The objective of this study is to identify the effect of N-D in gas well flowing at low rates, and to qualify the effect of N-D on the cumulative gas recovery. Non-Darcy Flow Effect in Low-Rate Gas Wells Table-1 shows data used to evaluate the effect of N-D on the well's flowing pressure using the analytical model of the N-D flow effect described in Appendix-A. Three different permeability values were used for the study, 1, 10, and 100 md. Three porosity values were used, 1, 10, and 20%. Five values of gas rates were included in the analysis, 0.1, 1, 10, 100, and 1000 MMscf/D. Using equations 4 and 5 a and b were calculated. F was calculated with equation 8. Figures 1 to 3 show F versus gas rates.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractField cases presented on this paper explain applications of Mechanical External Casing Packer (MECP) solving zonal isolation problems on openhole horizontal wells in Saudi Aramco. MECP is essentially a hybrid between existing casedhole conventional packer and inflatable External Casing Packer (ECP). MECP is different than ECP in the mechanism energizing the sealing element. The packer is run as an integral part of the casing string to provide a seal between the casing and wellbore. Saudi Aramco has successfully used MECP controlling water production, isolating fractured openhole sections, sealing casing shoe with leaking problem, and compartmenting openhole horizontal section.Included in this paper are four different field cases for openhole zonal isolation with MECP on horizontal wells. Each field case presents a particular application for the MECP. Technical data including well configuration and casing string are included in the paper. Field operations and lesson learned from each application are also presented in this paper.MECP has been successfully used for zonal isolation on openhole horizontal wells. Depending on the particular application, MECP can be run in combination with blank and/or screened pipe. Hole cleaning and wellbore conditions are factors affecting MECP placement.The knowledge provided in the paper can be applied to solving zonal isolation problems on openhole horizontal sections with different rock and fluid properties. The significance of this paper is that it presents actual field experiences and lessons learned for MECP applications. Furthermore, recommended field operations for successfully placing MECP on the well are also included in this paper.

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