Weighted Frac Fluids for Lower-Surface Treating Pressures

Simms, Lloyd Maurice; Clarkson, Brad A.; Navaira, Gilbert

doi:10.2118/112531-ms

Cited by 16 publications

(5 citation statements)

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“…The largest and most obvious benefit is lower surface treating pressures (Simms 2008). The HDF fluid substantially reduced surface treating pressures and treatment pressure trends were also reasonably predicted.…”

Section: Treatment Resultsmentioning

confidence: 64%

Development and Use of High Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs

Rivas

Navaira

Bourgeois

et al. 2008

SPE Annual Technical Conference and Exhibition

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In the Gulf of Mexico, there has been an increase in the number of wells drilled to depths greater than 20,000 ft with bottomhole pressures exceeding 20,000 psi. These deeper wells present drilling and completion challenges to the industry. Two of these challenges include fracture stimulation for low permeability and frac and pack sand control for higher permeability. Because of the high fracture gradient and friction in the wellbore tubulars, a conventional 1.0 to 1.04 SG fracturing fluid would require surface treating pressures greater than 15,000 psi. In the offshore marine environment, 15,000 psi pressure is the current limit of the flexible treatment line that transmits fluid from the stimulation equipment on the marine vessel to the wellhead on the rig.To solve this limitation, a borate-crosslinked high-density fracturing (HDF) fluid with of up to 1.38 was developed to harnesses the power of gravity and reduce the amount of surface treating pressure required to achieve adequate bottomhole fracturing pressure without exceeding the safety limits of the surface equipment. In numerous wells, a minimum of 20% reduction in surface treating pressure over the conventional 1.04 SG was recorded.This paper summarizes the well conditions, extensive fluid qualification testing, procedures, and selected job results along with final completion performance indicators.The HDF fluid enables treatment of these deep offshore wells by lowering surface treating pressure. Conventional 15,000 psi equipment could be used, less horsepower was required, and creating a safer work environment was achieved.

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Section: Treatment Resultsmentioning

confidence: 64%

Development and Use of High Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs

Rivas

Navaira

Bourgeois

et al. 2008

SPE Annual Technical Conference and Exhibition

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“…With an increase in solid concentration, the net pressure increases and so does the fluid density which ultimately increases the hydrostatic head, so a decline in surface pressure is observed. 4. Fluid properties within the study limits didn't affect the vertical propagation of the hydraulic fracture.…”

Section: Discussionmentioning

confidence: 90%

“…The study shows the effect of different combinations of fluid rheology, solids concentration and injection rate on the fracture geometry and net pressure (fracture pressure minus fracture closure pressure). This analysis helps to determine the maximum capacity of the formation along with the volume of waste it can hold and also provides an estimate of surface treating pressure [4].…”

Section: Introductionmentioning

confidence: 99%

Effect of Injection Fluid Properties on the Hydraulic Fracture Geometry: A Case Study from Texas

Im¹

2017

RAPSCI

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“…Increased Brine and Fracture Fluid Density: During recent years, a number of developments have taken place with heavy brine based frac fluids for deep formation opportunities, particularly in the Gulf of Mexico (Rivas et al, 2008) and (Simms et al, 2008). Increased Brine and Fracture Fluid Density: During recent years, a number of developments have taken place with heavy brine based frac fluids for deep formation opportunities, particularly in the Gulf of Mexico (Rivas et al, 2008) and (Simms et al, 2008).…”

Section: Increased Bottomhole Pressurementioning

confidence: 99%

StressCage and Frac Pack: Drilling the Conventionally Undrillable Without Creating the Unfraccable

Rylance

Mahadev

2016

Day 4 Thu, May 05, 2016

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There is little doubt that the success and reliability of frac-pack completions in the Gulf of Mexico has become the yard-stick by which Gulf of Mexico sand control completions are currently measured. Simultaneously, StressCage has become common practice as a method to overcome challenges drilling through depleted zones, in order to cope with complex mud-window constraints for new developments and infill wells. The success of these drilling and completion approaches and their rapid widespread application has resulted in ever more depletion. This has potentially created a vicious circle in terms of drilling the well to desired depth vs. the ability to install a low-skin frac-pack completion.While these two techniques in isolation represent uniquely optimal solutions to their individual challenges, there is growing evidence that their application within the same wellbore has the potential to create conflicting ideals. The StressCage application is associated with the plugging of small fractures which have been induced in the wellbore wall, thereby increasing the effective fracture gradient, which allows for the drilling of substantial depletion. However, the presence of a range of widely distributed particle sizes in the mud system, as well as increased general solids loading, may result in deep and invasive plugging of the permeable formations and any smaller fractures within the same open-hole sections. When these plugged formations are then the target for subsequent fracturing operations, there is a significant potential to create near wellbore problems that complicate or bring into question the ability to install a frac-pack completion.This paper will provide a number of examples of the application of StressCage, where resulting frac operations appear to have been hampered or complicated by the use of the StressCage approach and/or associated mud conditions. These examples will provide some evidence of such interactions but, more importantly, demonstrate the contradiction that these two techniques potentially represent. The paper will also outline a scenario resulting from a sand-control lower completion assembly in place, in a new borehole drilled with StressCage method, that could be resistant to any form of frac breakdown (or simple mechanical intervention), and, thereby, compromise the frac and well completion itself.In addition to the case histories, the paper will outline various engineering approaches that should be considered, including geo-mechanical analysis of well placement, identification of near wellbore issues prior to and during the fracturing operations, careful management of stress caged solids makeup, mud management and frac-pack design in order to avoid or overcome such challenges. All of this helps ensure that we do not create the paradox of being able to drill through the undrillable but then creating the unfraccable as a result.

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Weighted Frac Fluids for Lower-Surface Treating Pressures

Cited by 16 publications

References 0 publications

Development and Use of High Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs

Development and Use of High Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs

Effect of Injection Fluid Properties on the Hydraulic Fracture Geometry: A Case Study from Texas

StressCage and Frac Pack: Drilling the Conventionally Undrillable Without Creating the Unfraccable

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