A Multi-Well Review of Coiled Tubing Force Matching

Craig, Steven

doi:10.2118/81715-ms

Cited by 33 publications

(5 citation statements)

References 4 publications

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“…As far as the authors are aware, the relationship between temperature and CoF was never investigated for CT operations, either experimentally or theoretically. A similar study was reported by Kaarstad et al (2009) for drilling operations. There are several differences between wet dynamic friction for CT and for drilling operations.…”

Section: Introductionsupporting

confidence: 80%

“…However, it was observed that, in general, between 20 and 70 C, CoF decreases as temperature increases to approximately 40 to 45 C and then increases as tem-perature is increased further. Kaarstad et al (2009) obtained similar results (CoF increases with temperature) and proposed that fluid viscosity may be responsible for this effect (fluid viscosity decreases as temperature increases). They proposed a simple linear temperature dependence of CoF,…”

Section: Temperature-dependent Friction Modelmentioning

confidence: 54%

“…This means that a constant CoF has been assumed during both running-into-the-hole (RIH) and pulling-out-of-the-hole (POOH) processes, regardless of the downhole conditions such as temperature, fluid type, and surface roughness. For example, Craig (2003) analyzed the recorded vs. predicted weight data for 33 oil producers on Statoil platforms in the Norwegian sector of the North Sea and concluded that a constant value m ¼ 0.24 was representative for most of the wells, independent of the well-deviation complexity, production rates, and CT sliding direction (i.e., RIH or POOH).…”

Section: Introductionmentioning

confidence: 99%

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Increasing Lubricity of Downhole Fluids for Coiled-Tubing Operations

Livescu

Craig

2014

SPE Journal

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The requirement for intervention operations in long-reach lateral wells continues to grow. In the US, it is not uncommon to be asked to run coiled tubing (CT) in 10,000-ft laterals. In general terms, a 2-in. CT typically has enough weight reserves to perform work to approximately half such a lateral. Even though increasing the CT diameter remains a theoretical option to improve reach, practically, it creates logistical challenges with both road transport and offshore crane-lifting/deck-loading limitations. Although fluid-hammer tools and downhole tractors have extended the reasonable operational range of CT significantly, they also increase circulating pressures and operational complexity. To reach a 10,000-ft lateral, the use of metal-on-metal lubricants will be required to work in conjunction with the other systems.Obviously, the use of lubricants is not new. Typical real-life results of current systems are approximately a 15 to 20% reduction in the coefficient of friction (CoF) from a generic 0.24 to 0.19. Occasionally, one could obtain smaller CoF values in the field. However, these actual results compare poorly to laboratory testing with a high-pressure rotational friction test.An extensive set of laboratory measurements was carried out with a linear-friction measuring device to understand and quantify the mechanical, chemical, and thermal metal-on-metal wet frictional effects. Particular attention was paid to the synergy between lubricants and the other commonly circulated brines and fluid friction reducers. Other tests, such as regained-permeability and aging tests were also performed.Arising from the trials is a new lubricant that reduced the linear CoF by approximately 40 to 60% (0.10 to 0.12) under downhole conditions. Friction reduction of this magnitude is expected to make it feasible to run CT in 10,000-ft laterals without the use of fluid-hammer tools or tractors.

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Section: Introductionsupporting

confidence: 80%

Section: Temperature-dependent Friction Modelmentioning

confidence: 54%

Section: Introductionmentioning

confidence: 99%

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Increasing Lubricity of Downhole Fluids for Coiled-Tubing Operations

Livescu

Craig

2014

SPE Journal

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“…Craig (2003) reviewed coiled tubing injector weight data for 33 oil-producing wells and concluded that a constant friction coefficient of 0.24 was representative for most operations. Newman et al (2003) report that residual bending of coil increases the contact forces and effective friction significantly and show that the effective static friction coefficient is s ϭ 0.3 Ϯ 20%.…”

Section: Coefficient Of Frictionmentioning

confidence: 99%

Predicting the Extended Reach Capabilities of a Water-Hammer Tool with Variable Bypass Control

Kollé¹,

Theimer²,

Fraser³

et al. 2016

Day 2 Wed, March 23, 2016

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The ability to place coiled tubing into a long horizontal well is limited by friction and buckling. A water-hammer tool incorporates a self-piloted poppet valve that converts the kinetic energy of the fluid moving though the coil into water-hammer pressure pulses that reduce friction and applies an end load that pulls on the coil. Water-hammer tools allow routine entry into horizontal sections over 10,000 feet long, representing a significant increase over operation without these tools. These tools incorporate an internal fluid bypass to control the force applied to the bottomhole assembly. An external bypass may also be provided to allow higher flow rates for well circulation. A numerical model of coiled tubing injector weight for coiled tubing well intervention with a water-hammer tool is presented. The model includes the effects of fluid bypass and calculates the maximum feed rate at which a water hammer will be effective for extending the reach of coil. The model is available in spreadsheet format and may be used for job planning and parameter sensitivity analysis. The predicted effects of water-hammer impulse magnitude, fluid bypass, friction coefficient, flow rate, well inclination, and dogleg severity on horizontal reach are discussed. The results of the numerical model are compared with a sample of case histories from over 12,000 extended reach well interventions. These case histories confirm the extended reach capabilities of water-hammer tools and that reducing feed rate below the predicted maximum allows greater extended reach.

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“…Moreover, the friction factor, µ, highly depended on the roughness of contact surfaces, properties of the drilling fluid, and temperature and pressure conditions. Craig [56] analyzed 33 wells in a Norwegian platform and reported that µ = 0.24 was the most applicable friction factor for all types of wells, and the condition of the well trajectory had an insignificant effect on the friction factor. Table 1 lists the friction factors between the drill pipes and wellbore wall using different drilling fluids, as reported by Samuel [57].…”

mentioning

confidence: 99%

Heat Transfer Behaviors in Horizontal Wells Considering the Effects of Drill Pipe Rotation, and Hydraulic and Mechanical Frictions during Drilling Procedures

et al. 2018

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Horizontal wells are increasingly being utilized in the exploration and development of oil and gas resources. However, the high temperature that occurs during drilling processes leads to a number of problems, such as the deterioration of drilling fluid properties and borehole instability. Therefore, the insight into heat transfer behaviors in horizontal wells is certainly advantageous. This study presents an integrated numerical model for predicting the temperature distribution during horizontal wells drilling considering the effects of drill pipe rotations, and hydraulic (i.e., circulating pressure losses) and mechanical frictions. A full implicit finite difference method was applied to solve this model. The results revealed that the mechanical frictions affect more on wellbore temperature variation than the effects of heat transfer intensification and circulating pressure losses; Moreover, the drilling fluid temperature was found higher than the stratum temperature at horizontal section, the temperature difference at the bottom hole reached up to 16 °C if pressure drops, heat transfer strengthened by rotations and mechanical frictions were all taken into account. This research could be utilized as a theoretical reference for predicting temperature distributions and estimating risks in horizontal wells drilling.

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A Multi-Well Review of Coiled Tubing Force Matching

Cited by 33 publications

References 4 publications

Increasing Lubricity of Downhole Fluids for Coiled-Tubing Operations

Increasing Lubricity of Downhole Fluids for Coiled-Tubing Operations

Predicting the Extended Reach Capabilities of a Water-Hammer Tool with Variable Bypass Control

Heat Transfer Behaviors in Horizontal Wells Considering the Effects of Drill Pipe Rotation, and Hydraulic and Mechanical Frictions during Drilling Procedures

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