Slotted liner is commonly used for well completion to maintain borehole integrity and control production of sand, both in land and offshore. Due to length of horizontal wells, there is a pressure drop within producing wellbore, as a result of friction and turbulent flow. Additionally, radius of damaged zone caused by drilling fluid invasion is not constant along the horizontal well. Significant amount wellbore pressure drop and/or near well formation damage leads to non-uniform production profile along horizontal well. Consequently, unbalanced depletion of reservoir and problem of gas or water coning will occur. This paper represents an approach to eliminate occurrence of water or gas coning into producing horizontal wells which is based on precise manipulations and design of slotted liner parameters in such a way that the effect of wellbore pressure drop is compensated. Therefore, instead of running slotted liner with constant design parameters, they will vary deliberately along the well. Calculations performed by simulation software, developed based on theoretical concepts, which have been elaborately explained in this paper, comparisons between calculated data and measured field data have been made. When the modified parameters applied, total pressure drop along horizontal well approaches to an identical value. Additionally, this procedure of design can be used directly offset the effect of invaded zone around well. As the significant outcomes, with the help of this design method, production along the wellbore will be balanced and uniform. Additionally, if coning occurs, it will occur at tip of the well rather than happening at heel of horizontal well.
Horizontal well is a solution to accomplish higher production in thin reservoirs or those with very low permeability. However, these wells suffer from early water and gas conning and this jeopardizes the life of the well and its productivity. Therefore, having an understanding of the conditions in which coning occurs is highly desired. In this study several rock and fluid properties which affect water or gas breakthrough will be investigated and a few correlations are proposed to determine the breakthrough time and critical flow rate for the well in question. Ahwaz oilfield is one of the giant fields in the world and the reserves are estimated at more than 40 billion barrels. The reservoir is extremely heterogeneous latterly and vertically. Reservoir studies indicate that horizontal drilling is the best solution to increase ultimate recovery. However, the water and gas coning is the main problem in this field and several reports have shown the severity of this issue. A simulator has been written in FORTRAN to investigate the sensitivity of various parameters on well productivity and water breakthrough. The study shows that when the formation volume factor increases by 0.1 bbl/STB, the well productivity decreases by 2480 STB per day and also the water breakthrough time increases. In this paper it has also been shown that the reservoir under study with high permeability is not performing efficiently using horizontal wells since having high production in early times does not guarantee higher ultimate recovery. The dominant parameters in this case study are the horizontal well length and completion type. Using ICD (Inflow Control Device) certainly decreases the water-oil front movement towards the wellbore, and finally according to the simulation if the well had been drilled 320 ft above the water-oil contact instead of 127 ft, the critical flow rate would have been increased from 34000 to 210000 barrel per day.
One way of obtaining water-oil relative permeability curves is from co-injection (of water and oil) experiments at steady-state (SS) condition. The two-phase Darcy Law can be used to calculate the relative permeability directly only when water saturation is constant along the core. However, the capillary end effect (CEE) causes water accumulation or depletion at the end of the core depending upon the wettability. This work describes an improved method for correcting for this effect by modifying the "intercept method" initially proposed by Gupta and Maloney (2014). Similar to their work, we again envisage carrying out a steady-state co-injection experiment. For each ratio of water to oil flowrate (F=qwqo), we require experiments at several different total flowrates to be carried out. From each run, we obtain pressure drop across the core and average water saturation inside the core. We demonstrate mathematically that a plot of pressure difference vs. oil flowrate yields a straight line whose slope gives the oil relative permeability which can be used to calculate water relative permeability. A plot of average water saturation vs. reciprocal of oil flowrate gives a straight line whose intercept is the water saturation associated with the oil/water relative permeability values just obtained. It is necessary to perform the same experiment for at least two values of water and oil flowrates while the ratio is constant since we require at least two points to construct a straight line. The same procedure is used for other values of F to obtain more data points to construct the relative permeability curves. We have also mathematically corrected Gupta and Maloney’s work and other works after them and arrived at a simpler and more rigorous method. The details of how our method builds upon and improves their work will be published in due course (Goodarzian and Sorbie, 2020).
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