RYAN GIMMLER, Halliburton
Sharath Savari may not be able to predict the future—but he can tell you what the rock beneath your feet will do under stress.
Savari, global technical advisor at Halliburton, and his peers help redefine how the oil and gas industry approaches wellbore strengthening and stability. Their specialty? Geomechanics—the science of how rocks behave under stress. In an industry where the smallest miscalculation can cost millions, this work is nothing short of transformative.
Gone are the days when drilling relied on intuition and best guesses. Today, investing in advanced geomechanical modeling and geomechanics expertise enables operators to simulate subsurface conditions with remarkable precision, “stay ahead of the bit” and prevent problems before they ever arise.
For operators in the Delaware and Midland basins — two of the most prolific oil-producing regions in the U.S.—this shift is more than theoretical. It is reality. It means fewer surprises, less downtime and more efficient wells.
From rock science to rig site, Halliburton is turning geomechanical theory into executable precision across the Permian basin.
A STRESSFUL HISTORY BENEATH THE SURFACE
Since drilling began in West Texas in 1921, the region has faced significant geomechanical complexities related to formation instability. As operators draw from stacked reservoirs, the effect of hydrocarbon extraction has magnified and led to reservoir depletion. The production of hydrocarbons has sparked changes in the mechanical behavior of not only the production zones but also the areas around them.
One of the biggest risks is wellbore rock instability. Depletion of the reservoirs reduces pore pressure and causes the effective stress to expand within the rock matrix. This shift can lead to embrittlement, borehole collapse and increased size of cavings—all of which threaten well integrity and increase costs. The industry's push to produce more with less is a key business driver. Operators strive to achieve four-mile laterals that traverse multiple pressure-depleted zones.
Depletion comes in the form of pore pressure reductions and shifts in the formation. These shifts reduce the natural support for the rock. This can be seen throughout the Permian with micro-fracturing and deterioration of natural faults. These risks affect borehole integrity and increase the chance of lost circulation and well control issues.
The sheer number of diverse formations in the Permian basin further complicates matters. Any drilled well will enter and exit carbonate, clay, or sandstone-rich layers or a mixture of the three, all of which react in distinct ways under stress.
Drilling in West Texas has shifted from the management of depth and access limitations, such as horizontal drilling, to a greater comprehension of the mechanical consequences of depletion. As the basin matures, success depends on the industry’s ability to anticipate and mitigate the geomechanical risks that come with the extraction of natural resources from the formation.
Halliburton addresses this not only with advanced technology, but also with its most important asset—its people.
GEOMECHANICS INVESTMENT
When an operator decides to drill a well, it is imperative that the proper designs are in place to keep the formation in its natural state. It is essential to understand the rock from the inside out.
This is where Halliburton’s geomechanical team spends the majority of its time.
The company collaborates with operators to understand the nature of formations and the impact of stress on the rock. The team gives operators the unique ability to see not only how the rock will tolerate pressure, but also how it can improve and quantify wellbore stability.
For drilling fluids, Halliburton thinks of wellbore stability in terms of mud weights and equivalent circulating densities. Three key points are considered:
- Collapse pressure: If the selected mud weight is too low, the wellbore may collapse.
- Pore pressure: This is the pressure exerted by fluids (oil, gas, water) within the pores of the rock. It determines the mud weight required to keep those pressurized elements from the surface.
- Fracture gradient: The pressure gradient at which the formation will fracture and allow fluids to enter.
The determination of limitations on both sides is known as a mud weight window—understood by each operator’s geology department prior to drilling the well. When these factors are not well understood, operators face downtime costs, non-productive time (NPT) and well issues.
Consider a scenario where an operator drills a well and the difference in required mud weights between two zones is 0.5 pounds of mass per gallon (lbm/gal). This narrow margin is the difference between safe drilling in the formation below or significant lost returns in the formation above. Historically, an operator would do one of two things: drill the initial section and run a string of casing, or pump lost circulation material (LCM) and hope to remediate or prevent the losses.
This preventative approach is known as wellbore strengthening (WBS). WBS is the application of engineered particulates to a known fracture size in the anticipation that increased circumferential stress can improve the known fracture gradient beyond its previous limitation. This application increases the capacity of the formation to handle the extra pressure and expand the mud weight window. WBS is a valuable strategy for operators who strive to increase the mud weights in a field beyond their normal limitations and avoid problems, such as lost returns.
The issue with WBS has always been to understand the maximum mud weight. This is a challenge operators face, because today’s decisions shape tomorrow’s outcomes.
What if the upper limit could be defined? What if a diagnosis of the weaker formation could allow for the well to be drilled with that additional 0.5 lbm/gal of mud weight without lost returns or running an expensive string of casing? What if the problem of lost returns today became a thing of the past?
Answering these questions effectively was the goal. They sought to create software that predicts the fracture size of the formation and provides a new, expanded mud weight window with improved upper limit definition.
Savari and the team’s approach guides how WBS is applied, backed by sound engineering principles. “You cannot control the rock—but you can understand it,” Savari said. “And when you understand it, you can drill wells smarter, safer and longer.”
Development of the Drilling Fluid Graphics (DFG™) geomechanics modeling software program solved these challenges. This software looks at the prospective mud weight windows and how they are shifted with engineered WBS. It also conducts a fracture stability analysis to understand the risks of additional fracture propagation.
Once the wellbore is modeled, the appropriate LCM is understood, the new pressure tolerance or maximum mud weight is determined and the risk of fracture propagation is minimized, the team can safely drill ahead with confidence.
This is how Halliburton maximizes asset value for its customers with techniques designed to remedy problems before they happen. Modeling and chemistry have combined to help operators in North America reimagine their definition of wellbore stability.
CASE STUDY: GEOMECHANICS AND WBS AT WORK
Multiple operators attempted to use conventional methods to drill wells in North America that required drilling through a depleted sand formation in an intermediate hole section with weak formational pressure tolerances. These attempts resulted in NPT and suboptimal well performance, due to significant downhole losses—that includes thousands of barrels of nonaqueous fluid (NAF) lost to the formation. An expensive mitigation strategy employed by operators involved the establishment of an intermediate casing string to isolate the weak, pressure-depleted sand. While this approach enabled continued drilling through the curve and lateral sections with higher equivalent circulating densities (ECD) more than 13.5 lbm/gal, it also increased well construction costs, due to additional casing and cementing operations.
Fig. 1. Estimated fracture width and KI from the model.
TECHNICAL SOLUTIONS
The objective was to eliminate the intermediate casing string and achieve mud weights as if a string of casing were already in place in the wellbore. This helps to improve near-wellbore integrity and extend the operational drilling margin past the original 12.887 lbm/gal fracture gradient. This required the identification of LCM that could provide sufficient stress support and sealing capacity as a background additive in the active fluid system. The selected material also had to tolerate maximum expected ECDs without formation failure or fluid losses.
GEOMECHANICAL MODELING AND SOLUTION DESIGN
To address this issue, a geomechanical assessment was conducted with Halliburton’s proprietary DFG geomechanics software program. These models incorporated rock mechanical properties (e.g., in-situ stress, elastic moduli) and wellbore geometry to evaluate stress distribution, fracture behavior and wellbore stability at various concentrations of LCM.
Fig. 2. Wellbore stress enhancement model.
BaraShield®-981 LCM, a high-performance, multi-modal material with an engineered particle size distribution, was selected for evaluation. When incorporated into the active drilling fluid at a background concentration of 6.0 pounds per barrel (lbm/bbl), BaraShield-981 LCM demonstrated the ability to seal and stabilize fractures up to 500 micrometers (µm). It improved near-wellbore stress conditions and maintained wellbore integrity. Multiple models were conducted to simulate the native state of the rock and the formation tolerances prior to the introduction of WBS technologies and post-application.
MODELING INSIGHTS
- Fracture stability analysis: The DFG geomechanics software program fracture stability module showed that the fracture toughness or critical stress intensity factor, KIc, of the formation exceeded the estimated stress intensity factor at the fracture tip KI (Fig. 1). This indicated fracture stability with minimal risk of propagation.
- Wellbore wall stability assessment: Post-treatment analysis indicated favorable redistribution of stresses in the near-wellbore region to avoid secondary fracture initiation. The modeled fracture gradient exceeded the wellbore fracture limit after LCM incorporation, and a wellbore stress enhancement of 1.961 lbm/gal (Fig. 2). This improved formation integrity under elevated ECD conditions. The improvement translates to an increase in fracture mud weight from 12.887 lbm/gal to 14.848 lbm/gal.
FIELD IMPLEMENTATION AND RESULTS
Fig. 3. Expansion of the fracture gradient visual.
The solution was deployed throughout a four-well pad. With BaraShield-981 LCM incorporated into the fluid system, all wells were drilled to total depth, with ECDs that reach up to 14.074 lbm/gal, as steadily monitored via Halliburton’s DFG software program. This was well within the new expanded fracture gradient of 14.848 lbm/gal, up from the original fracture gradient of 12.887 lbm/gal, with no downhole losses encountered. This represents a strengthening of the wellbore by 1.961 lbm/gal.
The wells were completed without intermediate casing to isolate the depleted sands. The optimized drilling fluid strategy delivered a 9.31% improvement in the operational drilling margin and reduced the customers’ exposure to lost return events. In the Fig. 3 graph, the fracture gradient was analyzed prior to the application of the WBS material (fracturing MW) and post (new frac gradient).
Challenge: Deliver performance WBS materials to a wellbore to strengthen it and allow an operator to drill with a reduced casing string design in a well-known weak formation without losses.
Solution: DFG geomechanics software program paired with BaraShield-981 LCM WBS material. This solution improved the wellbore strength and allowed the customer to drill in an area with a casing design once thought unattainable.
Results: Elevated fracture gradient from a maximum of 12.887 lbm/gal to 14.848 lbm/gal allowed maximum ECDs on well of 14.074 lbm/gal without a lost return event. The customer saved an intermediate string of casing and negated the risk of costly lost NAF returns.
RYAN GIMMLER is the North America Land regional technical sales manager for Halliburton Baroid drilling fluids and is based in Houston. He joined Halliburton Baroid in 2011 and progressed from field operations to project management to account management. Mr. Gimmler has more than 14 years of experience in the industry, with expertise in operational execution and fluid design.
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