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.
© 2008. Society of Petroleum Engineers
View full textPDF
(
1,937 KB
)
History
- Original manuscript received:
31 August 2004
- Meeting paper published:
11 October 2004
- Revised manuscript received:
15 October 2007
- Manuscript approved:
10 January 2008
- Version of record:
25 June 2008
View Cart
