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Autor
Donald L. Whitfill is a Global Technical Advisor for Baroid Fluid Services after joining Baroid in 1997 as a member of the High Impact Technology Team.
Donald received his PhD in chemistry and taught one year as an instructor at the University of Oklahoma before joining Conoco Inc. in 1967. While with Conoco he served in a variety of R&D assignments including Group Leader of the Drilling and Completions Group and as Section Manager of the Reservoir & Recovery Section. During his career in the petroleum industry he has accumulated thirty publications plus twenty patents and has served in a variety of professional capacities throughout the industry including: Co-Chairman, AADE Fluids Management Group, 2005; Distinguished Lecturer, Society of Petroleum Engineers, 2005; Chairman, Reservoir and Recovery Forum, 1995-96; Board of Directors, Society of Petroleum Engineers, 1989-92; Distinguished Lecturer, Society of Petroleum Engineers, 1987, and Chairman, API Committee on Standardization of Drilling Fluid Materials, 1985-86.
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| Technology Solution Helps Reduce Drilling Non-Productive Time from Lost Circulation by Increasing Near Wellbore Area Strength |
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por Don Whitfill
- Global Technical Advisor
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For operators, lost circulation is one of the biggest contributors to drilling non-productive time. And, it is the most difficult segment of drilling in which to make economic decisions. Estimations of economic impact in this segment vary widely, but it is safe to say that it represents a very large portion of the total non-productive expense for drilling a well. And, as rig rates increase, the economic impact of non-productive time increases as well. Therefore, any technology that reduces drilling non-productive time can translate into millions of dollars in reduced drilling costs.
To address this problem, Halliburton offers engineered solutions designed to improve wellbore strength and reduce drilling non-productive time caused by lost circulation. This Wellbore Stress Management™ Service provides a fully engineered approach to lost circulation problems that requires both unique planning software and materials.
Lost circulation planning includes methods of preventing, as well as stopping wellbore fluid losses. While it is critical that lost circulations problems be solved, it is equally important that they be prevented because problems prevented represent money never expended. One important part of the preventive plan is the design of "borehole stress treatments". The goal of these treatments is to increase the "hoop stress" in the near wellbore region to improve the wellbore pressure containment ability.
Wellbore Stress Theory
Conventional fracturing theory predicts that lost circulation may occur when the tangential stress at the borehole surface exceeds the tensile strength of a rock. However, this conventional theory could not explain why lost circulation occurs more frequently when oil-based drilling fluids are used.
Based on research to answer this question dating back to the mid-1980s, it was determined that a stable fracture containing drilling mud with solid and gel components can exist and that lost circulation occurs when the fracture becomes unstable. This ultimately led to the conclusion that lost circulation mitigation could be enhanced by carrying materials in the drilling fluid that were of a proper size, concentration and type. The most significant result was not that lost circulation could be controlled by these treatments, but that the resistance to lost circulation (increased wellbore strength) could be enhanced significantly.
In 2001, a paper ("Formation Pressure Integrity Treatments Optimize Drilling and Completion of HTHP Production Hole Sections", Sweatman, et. al., 2001) was published that concluded "the pressure integrity of respective types and layers of rock can be restored and/or increased where the wellbore pressure may then exceed expected fracture initiation pressures." (Figure 1)
Figure 1: Improved Wellbore Pressure Containment (Click to enlarge)
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Later, in 2004, other papers added credence to these concepts and coined the phrase "stress cage" to describe the wellbore strengthening phenomena. Eventually, it was shown that high concentric stresses can be developed in the near wellbore region by inducing short fractures and plugging and sealing them with particles.
Methods to accomplish an increase in concentric stresses are described in a paper (SPE/IADC 92192, "Fracture Closure Stress (FCS) and Lost Returns Practices", DuPriest, 2005) in which the author points out that "fracture closure stress" is increased by widening the fracture to compress the adjacent rock. Closing stress determines the fracture reopening pressure and losses cannot occur if the fracture reopening pressure is greater than the equivalent circulating density (ECD). Losses are not stopped by simple plugging. Effective treatments should simultaneously isolate the tip and achieve adequate width.
WellSET™ Service
Halliburton has combined these concepts and principles into its WellSET service; a wellbore strength enhancing technology solution that increases the "hoop stress" (and thus the wellbore pressure containment ability) in the near wellbore region by placing a plugging material in an induced fracture to prevent further pressure and fluid transmission to the fracture tip, while at the same time widening and propping the fracture. (Figure 2)
Figure 2: Increased Hoop Stress (Click to enlarge)
Typically, the plugging material used in the induced fracture is a correctly sized resilient graphitic carbon and/or ground marble (Figure 3). Examples of these materials are unique products such as:
- Resilient graphitic carbon including BDF 391, 392, 393, and 398, as well as STEELSEAL® LCM and STEELSEAL Fine LCM.
- Sized ground marble including BARACARB® 5, 25, 50, 150 and 600 bridging agents.
Figure 3: WellSET Treating Materials (Click to enlarge)
Chemical lost circulation treatments that form a deformable, viscous and cohesive material also may have the ability to improve wellbore pressure containment as long as they can increase compressive stress at the fracture face. They include materials such as: FUSE-IT™ LCM, FlexPlug® OBM and W sealants, and FDP C-735 sealant. (Figure 4)
Figure 4: FUSE-IT Chemical Sealant (Click to enlarge)
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| FUSE-IT treatment reacted within a non-aqueous fluid |
FUSE-IT treatment reacted with a water-based fluid |
The chemical sealant systems are designed to react with the drilling fluid itself to create highly viscous and cohesive sealants in the wellbore that are displaced into the lost circulation fractures. FUSE-IT lost circulation treatment reacts over a wide range of water-based fluid mixing ratios while FlexPlug OBM slurry reacts with oil-based fluids. Also, the FUSE-IT treatment is capable of reacting within an oil-based fluid if a water pill is provided. These drilling-fluid-reactive systems are not dependent on temperature or pressure, thus removing a significant amount of placement uncertainty present with competitive systems.
Halliburton DFG™ software with DrillAhead® hydraulics module is used to predict the equivalent circulating density (ECD) over an interval in one module, calculate the width of a fracture that may be initiated, and select and design a proper material and particle size distribution that can efficiently prop and plug that fracture in a second module. (Figure 5)
Figure 5: DFG Near Wellbore Fracture Module (Click to enlarge)
A third module then predicts the change in rheology resulting from the addition of the specialized lost circulation materials, which then is cycled back to update the ECD calculations. (Figure 6)
Figure 6: Predicted Rheology after LCM Addition
Contingency chemical sealant treatment applications are designed using the DrillAhead® platform software package that models long fractures and provides fracture characterization for them. It also models lost circulation fracture length and width vs. ECD and provides planning for a chemical sealant treatment for lost circulation mitigation.
Gulf of Mexico Case History
Operator's Challenge
An operator working in the East Cameron area of the Gulf of Mexico wanted to sidetrack an existing well to increase production rates by cutting a window in the existing 9 5/8-in. casing and drilling to a total depth of 11,145 ft MD/ 10,515 ft TVD using oil-based fluid (OBF). However, there was significant risk of lost circulation in three severely depleted sand sections.
The Halliburton Solution
After the operator provided the data relative to the sand sections to the Halliburton team, DFG™ software was used to design the WellSET™ treatment for pre-treating the entire system. This determination was based on the anticipated permeability and subsequent pore sizes of the depleted formations.
The Halliburton team also used the software to determine the proper lost circulation treatment for each depleted sand package based on the estimated elastic rock properties and potential fracture widths initiated. Then the team recommended treating the active drilling fluid system with two additives: 9.8 ppb STEELSEAL® fine resilient graphitic carbon and 10.2 ppb BARACARB® 150-sized calcium carbonate.
Also, the treated system was supplemented with 15-20 bbl sweeps which were pumped every 100 ft. Each depleted sand section required a different treatment regimen according to the results determined by the WellSET treatment design.
The first depleted sand was drilled with a 10.0 ppg fluid. The sand package was depleted to a 5.7 ppg pore pressure. The equivalent differential pressure was +/- 1,095 psi. This section was treated with:
- 12.7 ppb BARACARB 150 sized calcium carbonate,
- 12.7 ppb BARACARB 600 sized calcium carbonate,
- 24.6 ppb STEELSEAL resilient graphitic carbon.
The second depleted sand was drilled with an 11.3 ppg fluid. The sand package was depleted to a 1.4 ppge pore pressure. The equivalent differential pressure was +/- 5,221 psi. This section was treated with:
The third depleted sand was drilled with an 11.5 ppg fluid. The sand package was depleted to a 4.0 ppge pore pressure. The equivalent differential pressure was +/- 4,100 psi. This section was treated as follows:
- 25.3 ppb BARACARB 600 sized calcium carbonate.
- 24.7 ppb STEELSEAL resilient graphitic carbon.
Results and Economic Value Created
The operator was successful in drilling each depleted sand package with no losses to the formation. Halliburton's Wellbore Stress Management™ service utilizing the DFG software virtually eliminated the "guess work" in designing the proper WellSET lost circulation treatment for the sand packages.
The operator was able to drill the well with no invasion of fluids to the formation that might have been damaging to the production reservoirs. No time was spent on attempting to control or cure loss returns. The use of the lost circulation program virtually eliminated losses to the entire well and allowed the operator to successfully complete the well and get it on production.
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