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Abstract This paper presents the results of a study designed to determine well testing procedures required to overcome the effects of formation damage from drilling, completion and other fluids in order to permit the derivation of realistic values of original formation permeability. A variety of possible drilling, completion and well testing conditions was modeled using a numerical multiphase reservoir simulator. Results indicate the possible lengths of the tests that may be required for various expected permeability ranges and how to allocate drawdown to buildup time permeability ranges and how to allocate drawdown to buildup time for a fixed testing time to optimize results. Introduction The validity of results obtained from formation testing in the presence of drilling and the fluid formation damage has been a question of considerable concern. In this investigation we have studied the effects of water imbibition from overbalanced drilling or completion fluids that are in contact with a gas bearing formation on the ability to derive formation gas permeability from subsequent well testing. Water imbibition in this study was controlled by overbalancing the formation's initial pressure with a specified hydrostatic pressure in the wellbore for a period of seven days. Following the imbibition period, the well was either immediately tested, shut-in for various lengths of time, before testing, or blown down and then shut-in for various lengths of time, prior to testing. The formation testing was performed by flowing the well to a minimum of 150 psia for a period of from 6 hours to 10 days. Each flow period was followed by a variety of buildup periods. Standard Horner plot analysis was then performed on the buildup data at hourly intervals. The permeability calculated by the Horner analysis was divided by the known value of formation permeability being studied and expressed as a percentage. This permeability being studied and expressed as a percentage. This percentage value was then plotted versus total test time. A comparison percentage value was then plotted versus total test time. A comparison of the plots for different drawdown periods for a given permeability and pretest conditions should indicate the optimum pretest conditions should indicate the optimum testing procedure for an anticipated permeability range and pretest conditions. pretest conditions. MODEL DESCRIPTION A three-phase, three-dimensional, fully implicit reservoir simulator, VIP was used to model the imbibition, other pretest conditions and the well testing itself. The reservoir model pretest conditions and the well testing itself. The reservoir model was gridded logarithmically into 28 rings from an inner radius of 4.38 inches, the wellbore, to an outer boundary of 20,000 feet. Pertinent formation and fluid data are contained in Table 1. Relative permeability curves, are depicted in Figure 1 and base case capillary pressure are shown in Figure 2. Capillary pressures were adjusted for the varying permeabilities according to the following formula. Pc (Sw) = Pcb (Sw) kb/k Pc (Sw) = Pcb (Sw) kb/k Wellbore storage effects were not included in this study since we considered only cases where the well was being shut-in downhole. No filter cake, skin, or other formation damage was incorporated other than that produced by increased water saturation from imbibition. BASIC CASES A range of formation permeabilities were studied in order to provide the test engineer a measure of the magnitude of total testing time required as a function of permeability. The formation gas permeabilities investigated were 2.6 md, 0.26 md, 0.025 md, 0.010 md and 0.0015 md. Water imbibition resulting from the pressure imbalance that the heavy drilling or completion fluid exerts on the formation was confined to a seven day period. During this seven day imbibition period, the wellbore fluid was held at a pressure of 680 psi above period, the wellbore fluid was held at a pressure of 680 psi above formation gas pressure. For the higher permeabilities studied, 2.6 md and 0.26 md, fluid losses were limited to 5 bbls per day, to reflect the fact that measures would be taken by the driller to restrict any excessive fluid losses. Several post imbibition scenarios were modeled to study the effects of varying the well environment prior to testing. The basic cases studied were: . 0 Day - no shut-in following imbibition.(Drill Stem Testing) P. 345 |
