Reduction in Backup Tool Requirements: Risks vs. Benefits, a Probability Analysis

Summary A review of the use of measurement while drilling (MWD), logging while drilling (LWD), and directional drilling (DD) tools mobilized to offshore drilling units in the North Sea highlighted an opportunity to lower operational cost for the operator and reduce capital used for the oilfield services company. An objective was set to develop a risk-based probability model that would assess the positive and negative financial impacts of reducing, or perhaps entirely removing, backup tools in this historically risk-averse basin. The scope of the initial analysis was a drilling campaign on a single rig contracted by the operator (Rig A). This analysis was then extended to review scenarios in which several operations in close proximity would share backup tools. The last 3 years of MWD/LWD/DD tool reliability data from North Sea operations, recorded by the oilfield services company, were used as an input. To assess the probability of failure, a binomial model was developed to create a binomial distribution for each tool to calculate the probability of having zero to X failures for a selected tool or bottomhole assembly (BHA) for a given number of runs. Three binomial models were developed to study the effect of “easy,” “moderate,” and “challenging” drilling environments on tool reliability. A financial risk model was designed to balance the probability-weighted cost of failure for the operator against the lower costs resulting from reduced tool provision by the oilfield services company. To better estimate risks and financial impacts on the project, a sensitivity analysis was performed on the financial risk model using the three binomial models. As a result of the analysis, it was demonstrated that recent improvements in tool reliability support a reduction in the provision of backup MWD/LWD/DD drilling tools for the majority of North Sea drilling scenarios.

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Probability-Derived Risk-Model: Lowers Costs through Reduction in Backup Tool Requirements, Improves Return on Capital Employed for the Contractor, and Reduces Scope 1 CO2 Emissions

10.2118/204021-ms ◽

2021 ◽

Author(s):

Steven Johannesen ◽

Thomas Lagarigue ◽

Gordon Shearer ◽

Karen Owen ◽

Grant Wood ◽

...

Keyword(s):

Co2 Emissions ◽

North Sea ◽

Financial Risk ◽

Risk Model ◽

Probability Of Failure ◽

Drilling Tool ◽

Drilling Tools ◽

Return On Capital ◽

Financial Impacts ◽

Binomial Models

Abstract A review of the utilization of Drilling Equipment highlighted an opportunity to lower operational cost for the Operator, reduce Capital Employed for the Service Company, and reduce industry Scope 1 CO2 emissions. The Operator and the Oilfield Services Company set the objective of developing a risk-based probability model that could be used to assess the positive and negative financial impacts of reducing, or perhaps entirely removing, the need for backup drilling tools in the historically risk-averse UK North Sea. The scope of the analysis was to be a drilling campaign on a single rig contracted by the Operator (Rig A). The last three years of Drilling tool reliability data from North Sea operations, as recorded by the Drilling Service Provider, were used as an input. To assess the probability of failure, a Binomial Model was developed to create a Binomial Distribution for each tool, before determining the probability of failure of a given drilling string. The method calculates the probability of having 0 to X failures for a selected Drilling tool/string for a given number of runs. Three Binomial Models were developed to analyze the effect of "Easy", "Moderate" and "Challenging" drilling environments on drilling tool reliability. A financial risk model was developed that balanced the probability-weighted cost of failure for the Operator against the lower costs resulting from reduced tool provision by the Service Provider. In order to better estimate the risks and financial impacts on the project, Sensitivity Analysis was performed on the financial risk model using the three Binomial Models. Scope 1 CO2 emission reductions result from fewer logistical movements and diminished backup tool manufacturing requirements. As a result of the analysis, it was shown that recent improvements in tool reliability support a reduction in backup Drilling tools for the majority of North Sea drilling scenarios, meeting the objective of reducing well construction cost while lowering carbon footprint. Open discussions, focused on maximizing economic hydrocarbon recovery, reducing costs for the Operator, improving Return on Capital Employed for the Oilfield Services Provider and reducing Scope 1 CO2 emissions, resulted in a commercial model that could deliver a Win-Win scenario for all parties. It was observed that the approach was scalable, and would deliver further benefit from a broader workscope, generating "network" benefits when applied to a cluster of rigs, and/or an entire play/basin. In addition, the risk model can be applied to alternative industry scenarios where strong reliability data exist.

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A Case History of Casing Directional Drilling in the Norwegian Sector of the North Sea

10.2118/112560-ms ◽

2008 ◽

Cited By ~ 2

Author(s):

Kevin Arthur Bourassa ◽

Tove Husby ◽

Rick Deuane Watts ◽

Dale Oveson ◽

Tommy M. Warren ◽

...

Keyword(s):

North Sea ◽

Case History ◽

Directional Drilling ◽

The North ◽

History Of ◽

The North Sea

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Significant Surge and Swab Offshore Brazil Induced by Rig Heave during Drillpipe Connections

SPE Drilling & Completion ◽

10.2118/200518-pa ◽

2021 ◽

pp. 1-8

Author(s):

John-Morten Godhavn ◽

Banzi Olorunju ◽

Dmitri Gorski ◽

Martin Kvernland ◽

Mateus Sant`Ana ◽

...

Keyword(s):

North Sea ◽

Sampling Rate ◽

Drilling Mud ◽

Long Distance ◽

Pressure Oscillations ◽

The North ◽

Order Of Magnitude ◽

Measurement While Drilling ◽

Well Trajectory ◽

The North Sea

Summary In this paper, we describe measured and simulated downhole pressure variations (“surge and swab”) during drillpipe connections when drilling an ultradeepwater well offshore Brazil on Bacalhau (former Carcará) Field. Floating rig motion caused by waves and swell (“rig heave”) induces surge and swab when the drillstring is suspended in slips to make up or break a drillpipe connection and topside heave compensation is temporarily deactivated. This is a known issue in regions with harsh weather, such as the North Sea, where pressure oscillations of up to 20 bar have been reported during connections. Recorded downhole drilling data from Bacalhau Field reveals significant pressure oscillations downhole (in the same order of magnitude as in the North Sea) each time the drillstring was suspended in slips to make a connection in the subsalt 8½-in. section of the well. Mud losses were experienced around the same well depth, and they might have been caused by surge and swab. Measured surge and swab pressure variations have been reproduced in an advanced proprietary surge and swab simulator that considers rig heave, drillpipe elasticity, well friction, non-Newtonian drilling mud, well trajectory, and geometry. Moreover, findings in this paper suggest that surge and swab was in fact significantly higher than recorded by the measurement while drilling (MWD) tool. The true magnitude of surge and swab is not captured in the recorded MWD data due to low sampling frequency of the downhole pressure recording (one measurement every 6 seconds, a standard downhole pressure sampling rate used on many operations today). This work shows that surge and swab during drillpipe connections on floaters may challenge the available pressure window for some wells, even in regions with calm weather such as Brazil. Managed pressure drilling (MPD) is a technique that improves control of the downhole pressure. It is, however, not possible to compensate fast downhole pressure transients, such as heave-induced surge and swab, using MPD choke topside. This is due to the long distance between the choke and the bit, which translates into a time delay in the same order of magnitude as typical wave and heave periods. A downhole choke combined with continuous circulation is one of the potential solutions. Surge and swab during drillpipe connections can result in a loss or an influx and should be considered in the well planning phase when mud weight, section lengths, etc. are selected.

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