Summary
Wellbore storage effects have been identified to significantly smear the accuracy of evaluating reservoir productivity through the fluid outflow rate from the annulus during underbalanced drilling. Such effects have continuously introduced considerable errors in characterizing the reservoir during underbalanced drilling. Conceptually, because of the ready volume-changing ability of the gas, wellbore storage becomes a determining factor during underbalanced drilling of a gas reservoir. Wellbore storage could either cause decrease (unloading effects) or increase (loading effects) in the annular gas density, depending on the choke opening procedures. Correspondingly, annular fluid outflow rate is considerably affected. Because it is practically difficult to deduct the fluid-flow rate attributable to the wellbore storage from the total fluid outflow rate, reducing the influence of wellbore effects on the evaluation of gas-reservoir productivity is presented in this study. Volumetric production analysis at the wellbore-sand face is introduced through a mathematical modeling of inflow of gas bubbles into the wellbore. This mathematical modeling utilizes forces such as the viscous force, drilling fluid ejecting forces from the bit nozzles, buoyancy, interfacial tension, and gas-reservoir forces for its analyses. Some analytical results that are overshadowed by wellbore storage are presented and supported by extensive experimental studies.
Introduction
One of the derivable benefits from underbalanced drilling is the ability to evaluate the productivity of a reservoir during drilling operations (Beiseman amd Emeh 2002). Other benefits include little to no invasive formation damage; higher penetration rate, especially in hard rocks; and lower cost of drilling operations if underbalanced drilling could consistently be maintained (Bennion et al. 2002). However, from the real-time bottomhole pressure measurements taken while drilling, it is obvious that continuous maintenance of underbalanced conditions at the bottomhole is difficult. Pressure surges that occur during some subsidiary operations such as pipe connections and surveys tend to jeopardize the avoidance of invasive formation damage (Yurkiw et al. 2002).
From the recent literature, reservoir evaluation has been approached through the estimation of the reservoir fluids flow rates into the wellbore. Assumption of the reservoir fluid inflow rate being the difference in the drilling fluid surface injection rate and the fluid outflow rate from the annulus has consistently been used (Kardolus and van Kruijsdijk 1997; Larsen and Nilsen 1999; Hunt and Rester 2000; Kneissl 200l; Lorentzen et al. 2001; Vefring et al. 2002; Biswas et al. 2003). So far, efforts in modeling reservoir fluid inflow have been concentrated on the oil inflow (Kardolus and van Kruijsdijk 1997; Larson and Nilsen 1999; Hunt and Rester 2000; Kneissl 200l; Lorentzen et al. 2001; Vefring et al. 2002; Biswas et al. 2003). These present approaches to production evaluation and characterization of gas formation recognize the important effects of wellbore phenomena, but have not been able to provide adequate means of reducing the influences. These wellbore phenomena include the gas-bubble coalescence and breakage, and bubble expansion and compression that are not possible to practically quantify during bubble annular upward flow. Because the present approaches involve the comparison of the surface fluid injection rate with the annular outflow rate, the influence of these phenomena on the gas formation evaluation is inevitable.
Unfortunately, all of these wellbore phenomena cause additional annular flow rates that cannot be individually and practically measured, and thus the reservoir fluid inflow rate at the bottomhole cannot be practically modified for their influences. Not recognizing the impact of such additional annular flow rates could cause misjudgment of the inflow capabilities of the gas reservoir. In order to properly alleviate these effects on gas-inflow analyses, a volumetric production analysis at the wellbore-sand face contact is presented in this study.
The conduction of gas-inflow analyses have been similarly performed as the liquid inflow in the petroleum engineering sectors. Practically speaking, gas inflow into a denser fluid system is bubbly in character, while liquid inflow is streaky. It is, therefore, proper to mathematically couple the forces of the viscosity, surface tension, inertia, and buoyancy that are responsible for gas-bubble formation or development to the drilling-fluid-ejecting forces from the bit nozzles and the reservoir forces in modeling gas-inflow scenarios.
Therefore, with the existence of underbalanced pressure conditions at the bottomhole, the modeling procedures presented in this study could be used for predicting the total volume of gas inflow with significantly reduced wellbore effects while drilling. This is possible as long as an underbalanced condition is maintained at the bottomhole.
This is a computer-simulation approach that utilizes real-time surface measurable underbalanced drilling data to predict quantitative gas volumes at the wellbore-sand face during drilling. As an additional advantage, the analyses do not involve knowing the gas inflow rate at the sand face, which could be difficult to accurately measure during underbalanced drilling operations. Standard engineering concepts are used to estimate downhole conditions for the analyses. Among the benefits from this study are reduced influences of the wellbore effects on the evaluation of gas-reservoir volumetric productivity during underbalanced drilling, the revealing of possible greater near-wellbore damage in some gas reservoirs, and possible in-situ permeability impairment through pore space compression.
Modeling of non-stationary fluid inflow to a multisectional horizontal well
