The potential for severe formation damage around horizontal wells exists due to the increased time of formation exposure to the drilling fluids as compared to the time that a vertical well is exposed to these fluids. This paper explains that the combined effect of the formation damage and the presence of impermeable barriers and low permeability regions in the vicinity of some sections of the horizontal wellbore will manifest itself as skin factor in well test analysis if the total drilled length of the horizontal section is used in the calculations. The purpose of this paper is to present practical new equations, based on a recently introduced concept in well performance analysis, for evaluating the effective length of the horizontal well contributing to unrestricted production. It is determined that the performance of a horizontal well with mechanical skin and of length Xf1 can be substituted by the performance of a horizontal well of length Xf2 with no skin. Xf2 is smaller than Xf1 for a damaged well and is greater than Xf1 for a stimulated well. By combining the concepts of equivalent horizontal well length and equivalent wellbore radius, one will be able to evaluate the performance of a horizontal well in comparison to its expected performance and to subsequently relate it to an equivalent stimulated vertical well. The new equations and guidelines can be used to determine the magnitude of formation damage around horizontal wells and to evaluate the success of a stimulation treatment.
The concept of effective horizontal well length developed in this paper was applied to the pressure drawdown analysis of well test data obtained on a horizontal well. A good match was obtained which were used to calculate the parameters of interest. Furthermore, the productivity index for this horizontal well was determined using the newly developed equation.
The poor performance of the eight horizontal wells drilled and completed in the Spraberry Trend of West Texas has largely been attributed to the severe near-wellbore skin problems. In order to increase the chance of intersecting the in-situ natural fractures, some of these wells were drilled perpendicular to the expected trend of the natural fractures (azimuth range of N75E to N8SE). Furthermore, all of these horizontal wells were hydraulically fractured. However, with the exception of one well, all of the horizontal wells drilled in the Spraberry Trend were economic failure. Among other factors, the plugging of natural fractures by the drilling and fracturing fluids could be the possible reason for the economic failure of these wells.
Possible reasons for the poor performance of the horizontal well drilled in the Galoc clastic unit (located off Philippines in South China Sea) are:
the porosity of the rock may have been low,
the formation may have had very low vertical permeability, and
the sandface may have been extensively damaged.