Challenges while drilling pre-salt wells offshore Brazil have led to planed hole enlargement operations as part of the drilling solution of this type of imviroments in vertical sections from 18-1/8Љ x 22-in. However, this application proved to be challenging for the hydraulic underreamer cutting structures as high vibration levels together with increased cutter block matrix exposure to the formation led to premature wear on the hydraulic hole enlarger cutter blocks.Formation to be enlarged is composed of 40% disaggregated sandstone, 40% shale and 20% mudstones, the objective was to enlarge intervals that ranged from 850 mts to 1000 mts in one run. The BHA was experiencing high levels of shocks and vibrations that forced the operator to make additional trips to finish enlarging the section. These additional trips proved to be costly high with rig rates between $750,000-$1million USD.Efficiently undereaming while drilling the entire section depth in one trip as planned would be challenging and present a significant risk because of high daily rig-rates. To achieve objectives, a Finite Element Analysis (FEA)-based simulation was performed aimed at improving BHA design and to evaluate a new desing of underreamer cutter block with the objective of improving cutter durability as well as reducing stresses experienced while enlarging the wellbore.The study used a well records database and numerous offsets runs with a hydraulic expandable underreamer used in offshore applications. A rock-strength identification program, that uses log data including GR and sonic, was applied to determine formation type and foot-by-foot UCS. A hydraulic analysis was also performed to determine efficient hole cleaning as well as ensuring adequate flow distribution to ensure correct functionality of different BHA components, finally a FEA-based modeling system identified the following key points:The BHA used in previous application had room for improvement by modifying the size of DCs used and by using a concentric expandable stabilizer to improve drilling efficiency and reduce vibration. A new cutter block re-arrangement was designed for the application with changes including: 1) introduction of a three row cutter-block with increased PDC density and optimized stresses distribution; 2) adjusted cutter block nose design for more efficient hole coverage; 3) reduced depth-of-cut without compromising ROP potential; 4) define an optimal operating parameters window with conclusions drawn from results of the FEA-simulations aimed at improving ROP and reduce levels of stresses at the hole enlargement tool.The new-style BHA was run and underreamed while drilling 734 mts without requiring an additional trip to finish enlarging the section. The BHA also improved ROP during the UWD run. This new system saved the operator between 96-120 hrs of rig time and met the objectives set when compared to offset wells for similar applications.
Directional Casing while Drilling (DCwD) in Ecuador has been technically evaluated as a well construction technique to reduce or mitigate operational problems associate with: 1) constructing wells that could not be drilled efficiently using conventional techniques in partial and total lost circulation scenarios, through swelling shale or with hole instability issues, tight hole or stuck-pipe applications; 2) or to reduce total operational costs by eliminating casing runs, short/wiper trips and increase ROP.At last count there have been over 200 worldwide directional casing drilling runs both onshore and offshore. These runs have been successfully executed in some of the most challenging drilling theaters making DCwD a viable and cost reducing alternative which helps operators solve the previously mentioned problems. To support the introduction of DCwD in Ecuador, rigorous engineering analysis has been performed which involves both the economic and technical aspects to help determine what kind of casing drilling system and BHA configuration is most suitable to ensure a successful run.Modeling sofwares have been used to evaluate drilling dynamics and hydraulic requirements enabling engineers to select a drillstring that is capable of performing the specified job and obtain the required performance improvement with DCwD. The digital analysis helps to accurately predict if the application is suitable and determine which parameters could be applied to efficiently and safely execute the DCwD application.There are some factors or parameters that can be taken as benchmarks when analyzing both static and dynamic simulation results. Torque determines if the rig has the capacity to drive the system. Fatigue and buckling analysis provide inferences into casing pipe selection and connection type. Realistic friction factors used during the simulations will avoid obtaining erroneous results which could lead to serious drawbacks. Scenarios like magnetic interference, presence of conglomerates or boulders could limit the tools' used for a specific application. The recommended BHAs will be supported by the specific regional analysis in addition to successes in other similar worldwide applications.Once the engineering analysis has been completed, economics are then considered. The directional casing drilling service cost versus the amount of saving obtained by applying this technology has to be thoroughly evaluated. Savings will be couched as either time and/or money. Both have to be evaluated in the short and long term to determine which applications would benefit from DCwD and which environments should be avoided. The authors will explain how this analysis is performed to obtain an adequate feasibility study to meet the client's objectives. They will also discuss the key performance objectives that must be considered during each step of the analysis.
To reach the reservoir in Campos Basin, deepwater Brazil requires the operator to drill a difficult "S" shaped wellbore geometry through shale and sandstone with UCS (5-15kpsi). To achieve the objective, an operational plan was devised that had two major phases: 1) drill to the base of the reservoir in under-reaming mode building angle from 30°to 80°while enlarging the hole 12¼-in x 14¾-in for 600m; 2) then drill 300m of 12¼-in drop-off section down to 3700m MD. After reaching 12¼-in TD, the plan calls for reservoir evaluation then pumping a cement plug to sidetrack and drill a long horizontal section. Efficiently delivering the relatively deep wellbore as planned would be challenging and present a significant risk because of daily rig-rates approaching $1 millon USD. To ensure all contingencies were considered, the operator initiated an engineering analysis to identify tool/BHA limitations: 1) Using a reamer to drill into the reservoir would have a negative effect on ROP and require the operator to pump more cement for the sidetrack plug; although improved image quality would be achieved by logging in the smaller 12¼-in hole section.2) The operator also considered placing the concentric reamer 300 -400m offset from the bit to drill the drop-section without tripping to remove the reaming tool from the BHA. However, this BHA configuration would be susceptible to vibration induced RSS/MWD/LWD damage, drilling dysfunction and would also increase the risk of a parted connection.To solve the application changes, an engineering analysis was conducted to determine if a new-type ream-on-demand (RoD) tool would be an appropriate solution. Since the RoD tool is equipped with an innovative hydraulic system, it can perform multiple activations/deactivations of the cutting blocks while downhole. Because the RoD system does not require a ball drop to engage, BHA design flexibility is greatly enhanced.The study used a well records database and numerous offsets runs with a conventional expandable reamer used in Roncador field. A rock-strength identification program, that uses log data including GR and sonic, was applied to determine formation type and foot-by-foot UCS. A hydraulics analysis was performed to determine proper operational and indexing flow rates. Finally, an FEA-based modeling system identified an optimal parameters window (RPM/WOB) to reduce damaging vibration levels while reaming/drilling. The RoD tool was run and drilled a 12¼-in hole into the reservoir without requiring a trip that is required to lay down a conventional ball-drop activated reamer. The new-style BHA also improved ROP when drilling into the reservoir. The RoD system saved the operator between 24 -36 hrs of rig time for a cost savings of approximately $1 million USD. The operator plans to keep using the ream-on-demand tool in future applications where the "S" well profile is required.
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