Your account already exists. Please login first to continue managing your settings.
Integrating geomechanics with drilling fluid design successfully mitigates time-dependent wellbore instability in Middle East fields.
Operators worldwide lose billions of dollars every year — sometimes millions in a single well — due to drilling problems caused by time-dependent wellbore instability in clay-rich shale formations. Formation failure and borehole collapse cause stuck pipe, casing delays, loss of expensive tools in the hole, and undesirable sidetracks. Unstable hole conditions unnecessarily increase non-productive time (NPT), inflate the costs of equipment and materials, and impact the quality of critical formation evaluation data.
The time-dependent shale instability challenge
|Processes of Mud Pressure Penetration (?P) and Chemical Potential (???) Mechanisms.|
A combination of stress and pore pressure conditions around the well bore, related in part to incorrect drilling fluid salinity and type and improper mud weight, cause many costly time-dependent wellbore instability drilling events. “Time-dependent” refers to wellbore stability conditions that change over time. Often, a delay of several days occurs between initial exposure of a shale section to drilling fluid and the onset of instability-related drilling problems. Drilling through several quite different shale formations can significantly complicate the challenge.
The subtle interaction between two complex mechanisms — mud pressure penetration and chemical potential — controls wellbore stability while drilling through shale under common overbalanced conditions.
Because shales exhibit low permeability and filtration rates, when a drilling fluid comes in contact with a shale formation, an inadequate amount of drilling fluid solids will deposit on the wall of the well bore to create an effective flow barrier. Due to the first mechanism — mud pressure penetration — small amounts of mud filtrate begin to penetrate the shale, increasing pore pressure near the well bore wall over the next few days. As pore pressure increases, it causes a decrease in the effectiveness of mud support. It will gradually lead to unstable wellbore conditions and failure of the wellbore wall, which can wreak havoc on subsequent drilling operations.
The flow of water into or out of shales is also controlled by a second mechanism — the chemical potential gradient between the drilling fluid and the formation’s in situ pore fluid. This gradient is created largely by differences in salinity, with water flowing from low-salinity fluid to high-salinity fluid. As long as osmotic outflow from the shale is able to counteract the mud pressure penetration, the chemical potential difference across the semi-permeable barrier will prevent elevated pore pressure and maintain the effectiveness of mud support. However, if the drilling fluid salinity is lower than the salinity of the formation pore fluid, the osmotic inflow into the shale will further boost pore pressure increase and make the well bore even more unstable.
To avoid time-dependent shale instability, therefore, these two mechanisms must be in delicate balance. The salinity of the drilling fluid must be high enough relative to the formation pore fluid for the chemical potential mechanism to counteract the mud pressure penetration. This balance is tough to determine by conventional methods.
Many operators and service providers treat shale-related wellbore instability as largely unavoidable, grit their teeth, drill through the difficult section quickly, and run extra casing. Not only is this approach more expensive, but also a smaller hole size in the pay zone can impact production rates for years to come. Often drillers switch from water-based to oil-based mud, assuming this will automatically remedy the situation. However, shale problems can still occur with oil-based mud, especially when the underlying mechanisms are poorly understood. Some operators may have a geomechanical service provider perform a study of the geomechanical wellbore instability component while another service provider designs the drilling fluid. Rarely do the two providers talk to each other to come up with effective solutions. As a result, many drillers establish local “rules of thumb” by trial and error. Unfortunately, the “error” part of that equation may cost millions of dollars and create unnecessary delays.
Time-dependent shale instability in the Khafji field
|Location of Khafji field.|
Al-Khafji Joint Operations, a joint venture between Aramco Gulf Operations and Kuwait Gulf Oil Co., is developing the offshore Khafji field in the Arabian Gulf. Since long-reach and horizontal drilling operations began a few years ago, wells have encountered severe time-dependent wellbore stability problems due to shale sloughing. Wellbore instability has caused stuck pipe, lost-in-hole events, and sidetracks in every third well. As a result, Al-Khafji Joint Operations consulted Schlumberger about potential solutions.
Schlumberger has run into similar problems elsewhere and has developed a unique field-based methodology which has been applied successfully in the Middle East, Central Asia, Asia, Australia, and Europe to date. The approach integrates drilling fluid design with geomechanics in a single study to address stress-induced effects and time-dependent fluid effects holistically.
Phase 1 of the Khafji field study focused on three problematic shales — two above and one between the main reservoir sands. A drilling event review of seven offset wells identified specific problems associated with tight spots, pack-off, and stuck pipe. Stress-induced wellbore stability analysis of the offset wells improved understanding of borehole deformation and failure mechanisms while validating the mechanical earth models at the same time. In addition to input from the stress-induced wellbore stability analysis, the time-dependent wellbore stability analysis also used a range of measured petrophysical and chemical properties of the shales from cuttings and cavings, measured or estimated drilling fluid properties, overbalance pressures, and formation temperatures from selected offset wells. The integrated study determined that time-dependent instability-related drilling events in the Khafji field had been caused primarily by insufficient salinity in the drilling fluid. Hence, the chemical potential mechanism had been inadequate to counteract the gradual rising pore pressure due to the mud pressure penetration.
Specifications were subsequently provided for water-based muds — both salinity and weight — based on the integrated study on these three shales.
Value achieved by implementing study solutions
The first horizontal well using the proposed solution was completed without any significant problems or NPT related to time-dependent wellbore instability. This clearly showed that water-based mud with the correct salinity and mud weight was capable of preventing the severe drilling events encountered in previous wells.
Since then, studies on three additional horizontal wells and four reentry wells in the Khafji field have been conducted implementing the unique drilling fluid design optimization methodology. All wells were drilled and cased to total depth (TD) on time and without significant NPT due to shale instability. This represents a step-change in drilling performance that provides an effective approach to counteract wellbore instability that had been plaguing the field.
Drilling eight wells without losing costly drilling and logging equipment in the hole, while reducing both fishing time and the cost of redrilling sidetracks, has saved millions of dollars. Factoring in the cost of the original study and the incremental cost of applying the optimized drilling fluid design to each new well, it has cost Al-Khafji Joint Operations only about 5% of the total amount saved per well to pay for this new technology. In other words, about 40% of the amount of money saved in the very first well covered the design costs for all eight wells. This represents an excellent return on investment.
There have been additional benefits achieved as well in the Khafji field.
For example, hole conditions have become much better for logging-while-drilling due to a reduction in breakouts. Smoother wellbore shape has enhanced the quality of formation evaluation data acquired in those wells. In addition, improved hole conditions have reduced unnecessary costs associated with cementing, since the need for excess cement has been minimized. With less cement to drill through, tool failures due to high vibration have also been reduced, further saving operational expenses.
This methodology was so successful with the first three shales that Al-Khafji Joint Operations decided to extend the study to three additional shales, deeper in the Khafji field. Every shale is somewhat different, so each horizontal well must be planned independently. Once the underlying time-dependent wellbore instability mechanisms are understood, the costs of mitigating those effects are tiny compared with the ultimate payoff.
The optimal approach lies in integrating wellbore geomechanics with drilling fluid design to generate holistic solutions. To this end, a worldwide patent has been filed on this field-based drilling fluid optimization methodology for time-dependent shale stability problems. The method applies to all shales and all mud types.