Hydraulic fracturing of reservoirs which demonstrate a tendency for fluid retention, can result in low fluid recovery and poor productivity.

We assert that the effects of fluid invasion on formation permeability in reservoirs with ultra-low water saturations has been over-dramatized, perhaps because the mechanisms of permeability reduction as a result of fluid invasion are not well understood. It has been proposed that some reservoirs contain less than irreducible water, Swirr (based on capillary pressure), and as such, have additional pore volume which contributes to hydrocarbon permeability. Consequently, introduction of fluids during drilling and completion could result in more permeability loss in these reservoirs, than in reservoirs which contain water saturations controlled by capillary pressure. This paper demonstrates, with actual laboratory data and with Poiseuille's theory, that for water-wet reservoirs (which most gas reservoirs are, since gas is strongly non-wetting) areas of porosity where bound water exists (or any other wetting fluid) contribute little to the overall permeability. Several permeability measurements performed on clastic, limestone and dolomite core samples with and without connate water saturation demonstrate that minimal permeability reduction occurs due to the presence of an irreducible water saturation. Even in extremely low permeability cores less than 0.5 md, the effect of irreducible water saturation on gas permeability was only a 20% reduction. These results suggest that permeability damage is only slightly worse in desiccated gas reservoirs than in conventional gas reservoirs. Furthermore, permeability impairment as a result of fluid invasion is more a function of effects on macroporosity than microporosity. Introduction With the increased activity in natural gas exploitation in Canada, much attention has been drawn to the potential for formation damage as a result of the introduction of drilling and completions fluids, particularly in low permeability gas reservoirs. A perception exists that damage may be greater in reservoirs which are initially at ultra-low water saturations; i.e., lower than what might be predicted from capillary pressure measurements. This thinking differs from the general consensus that microporosity, which is the major portion of pore volume controlling water saturation in a water-wet reservoir, contributes little to permeability. This paper reviews various literature views on the relationship of pore size and water saturation with respect to contributions to permeability. Laboratory permeability measurements on cores from four formations are presented and compared to other published data, to demonstrate the effect of water saturation on effective permeability, and how it relates to capillary pressure and pore throat size. Finally, a technique will be presented, based on Pouseille's theory, showing how to calculate the contribution to permeability as a function of pore throat size using air/mercury capillary pressure data. Literature Review Thomeer(1) and Swanson(2) developed empirical techniques for predicting absolute permeability from capillary pressure data. They recognized the insignificant contribution to permeability of smaller pores compared to the contribution of larger pores. Swanson's method of characterizing capillary pressure curves uses the inflection point (point A in Figure 1) on the lower portion of the curve to predict permeability. He argued that this inflection point represents the maximum product of pore throat size times effective flow area.

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The popularity and breadth of appbeatign of horizontal well technology continues to expand. In some cases, however, hon'-zontal well performance is disappointing -often as a result of drilling-induced formation damage. This damage may occur over the entire pay interval, or may occur in discreet intervals in varying degrees, depending on drilling conditions and changes in lithology along the wellbore The resultant inflow may occur over one or more short,segments rather than the entire horizontal wellbore. This limited drainage profile can lead to premature coning, and poorer than expected perfommee.Formation damage is normally modelled using a skin factor, s, in the Darcy flow equation, assumed to be a constant. The skin value used, if not measured directly from pressure transient analysis, can be based on tabofatory regain permeability tests conducted on core samples. These tests involve comparing the final (regain) permeabiltiy, after mud damage during leakoff, to the initial underdamaged permealbility. The final regain permeabili-ty is typically measured at some arbitrary flow rate (and there-fore, some arbitrary drawdown). Our research indicates that this test method is over-simplified because it does not recognize the variable nature in which wellbore cleanup occurs.A more comprehensive test procedure has been developed for mud leakoff and regain permeability testing , whereby the regain permeability is measured at incrementally-increasing pressure differentials across the core. Imposing a pressure differential and measuring the resultant flow rate is consistent with applying a drawdown in the actual well. Application of the new test pro-cedure with different drilling muds on several core plugs of varying permeability indicates that fluid inflaw will not occur until a minimum "threshold pressure" is achieved. Lab results showed distinct differences in threshold pressure magnitude between different mud systems and rock permeability. Regain permeability improves with increasing pressure drop and W'th increasing volumetric diroughput. In some cases, it returns to its non-damaged value.A finite-difference wellbore simulator has been developed, incorporating the dynamic cleanup effect, to model early-time transient productivity in a horizontal well. The model predicts significantly poorer flow-contribution profiles than might be expected from the flow-capacity (kh) profile. The model also demonstrates how uneven wellbore cleanup is more likely to result in shorter effective well lengths in low-viscosity, high-permeability (high flow-capacity) reservoirs. In these reservoirs, where horizontal wells are often drilled for coning mitigation, shorter effective well lengths can lead to unexpected premature coning. May 1995, Volume 34, No. 5 Introduction Drilling,-induced formation damage is recognized as a potential cause of lost well productivity(l). With horizontal wells, formation damage presents increased difficulties because: a) formation damage is often more severe( ). b) stimulation costs to overcome damage are h...