Increasing Effective Fracture Gradients by Managing Wellbore Temperatures
- Manuel Eduardo Gonzalez (ChevronTexaco Exploration and Production Technology Company) | James Benjamin Bloys (ChevronTexaco Exploration and Production Technology Company) | John E. Lofton (ChevronTexaco Exploration and Production Technology Company) | Gregory Paul Pepin (ChevronTexaco Exploration and Production Technology Company) | Joseph H. Schmidt (Frac Dogs, Inc.) | Carey John Naquin (Landmark Graphics Corporation) | Scot Thomas Ellis (Landmark Graphics Corporation) | Patrick E. Laursen (Landmark Graphics Corporation)
- Document ID
- Society of Petroleum Engineers
- IADC/SPE Drilling Conference, 2-4 March, Dallas, Texas
- Publication Date
- Document Type
- Conference Paper
- 2004. IADC/SPE Drilling Conference
- 1.14.3 Cement Formulation (Chemistry, Properties), 3 Production and Well Operations, 5.9.2 Geothermal Resources, 1.7 Pressure Management, 2.1.7 Deepwater Completions Design, 4.3.4 Scale, 1.12.6 Drilling Data Management and Standards, 1.2 Wellbore Design, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.10 Drilling Equipment, 1.11 Drilling Fluids and Materials, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.6 Drilling Operations, 4.2.4 Risers
- 2 in the last 30 days
- 896 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 28.00|
Thermal effects on wellbore stresses can have a significant impact on effective fracture gradients. Changes in wellbore temperatures caused by various drilling operations provide for these thermal effects. For example, circulation on bottom usually results in lower bottom hole temperatures than the static geothermal temperature. This cooling effect reduces the wellbore stresses resulting in lower effective fracture gradients. Minimizing the cooling effect by increasing wellbore temperatures can increase effective fracture gradients and the corresponding pore pressure/fracture gradient margin avoiding costly lost circulation and additional unnecessary casing points.
This paper presents results from leak-off tests taken at various temperatures which demonstrate the thermal effect on formation stress. This paper also examines the effects of operational factors on wellbore temperatures to minimize the cooling effect and/or increase effective fracture gradients. Software developed for thermal simulation of various drilling operations was used to perform the analysis.
An investigation of historical lost circulation events, particularly in deepwater environments, resulted in considering the thermal effects on formation stress as a possible cause. A test was performed where leak-off-tests were taken at varying temperatures to confirm that the results would indeed be affected by wellbore temperature. The results of this test are presented in this paper. Subsequent analysis of historical lost circulation events in several deepwater wells indicated that at a minimum, there was at least a strong correlation between wellbore temperatures and a significant number of these lost circulation events for which several examples are presented in this paper.
An understanding of the various factors that influence wellbore temperature was then needed to develop ideas as to how wellbore temperature might actually be managed to potentially prevent what can be referred to as thermally induced lost circulation. Thermal simulation software based on work by Mitchell and Wedelich1 was used to run a sensitivity analysis on a deepwater example well of the various controllable factors that influence wellbore temperatures. The results of this analysis are also presented in this paper.
Thermal Effects on Formation Stress
Timoshenko and Goodier2 presented an elastic theory which describes the effect of thermal stresses around an infinitely long cylinder containing a circular hole. In it, they showed that heating the inner wall of the cylinder will result in an increase in the compressive forces around the hole. Perkins and Gonzales3,4 discussed an analytical solution to the thermoelastic problem, showing that injecting large volumes of liquid that is colder than the in-situ reservoir temperature can significantly reduce the fracturing pressures in the formation. Tang and Luo5 presented model predictions of the effect on the near-wellbore stresses of differences in temperature between the mud in the wellbore and the formation. Figure 1 shows the results of their simulation of a 15 hour mud circulation period followed by a 15 hour noncirculating period. They predicted a tensile stress of 1015 psi around the wellbore after the 15 hour mud circulation period, followed by a gradual reduction in the tensile stress during the non-circulating period.
|File Size||387 KB||Number of Pages||14|