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This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142282, โThe Hydraulic Effect of Tool Joints on Annular-Pressure Loss,โ by Majed Enfis, SPE, and Ramadan Ahmed, SPE, University of Oklahoma, and Arild Saasen, SPE, Det Norske and the University of Stavanger, prepared for the 2011 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 27-29 March. The paper has not been peer reviewed. For a successful drilling operation, downhole pressure, or equivalent circulating-density (ECD), control is critical. Conventional drilling techniques require maintaining the bottomhole pressure (BHP) at a level between the pore and fracture pressures. In deepwater wells, the margin between these pressures is veryย narrow; therefore, the BHP and ECD must be predicted accurately and be maintained within that narrow margin to avoid kicks and circulation losses. The presence of a tool joint changes the annulus geometry between the drillpipe and the casing or hole, resulting in strong turbulence and fluidย acceleration that generate additional viscous dissipation and pressure losses. Theoretical and experimental studies examined the hydraulic effects of rotating and nonrotating tool joints. Introduction While drilling oil and gas wells, drilling mud is circulated in the wellbore to transport cuttings to the surface and control the BHP. In conventional drilling operations, the mud is injected into the well through the drillstring (drillpipe) with a high-pressure pump. The mud flows through the drillpipe and exits the drill bit where it enters the annulus and flows up the annular space to the surface carrying rock cuttings. Significant pressure losses occur as the mud flows through the drillpipe and the annulus. The BHP, which is a critical parameter in any drilling operation, is a function of the hydrostatic head of the mud and annular-pressure loss. Hence, accurate prediction of the annular-pressure loss leads to a good estimation of the BHP and the ECD to prevent kicks and circulation losses. The ECD is a commonly used drilling term that represents the BHP in terms of equivalent fluid density. This means that it combines the density of the fluid and annular-pressure loss. Previous studies focused on the hydraulic effects of a nonrotating tool joint. The purpose of this study was to examine hydraulic effects of tool joints under both static and dynamic conditions, and to develop models for predicting the change in annular-pressure loss caused by the tool joints.
- North America > United States > Oklahoma > Oklahoma County > Oklahoma City (0.25)
- Europe > Norway > Rogaland > Stavanger (0.25)
- Europe > Germany > North Rhine-Westphalia > Dรผsseldorf Region > Dรผsseldorf (0.16)
This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19550, "Overcoming Weight- Transfer Challenges in Complex, Shallow, Extended-Reach Wells on Alaska's North Slope," by Randy Thomas, SPE, Dennis Hartwig, and Steve McKeever, SPE, ConocoPhillips Alaska; Dave Egedahl, SPE, ASRC Energy Services E&P Technology; John Patton and Keith Holtzman, Halliburton-Sperry Drilling Services; and Lee Smith, Halliburton-Security DBS/ Alaskan Energy Resources, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. The complex wells constructed to develop the West Sak field on the North Slope of Alaska are approaching the limits of extended-reach-drilling technology. With the shallow vertical depth and long horizontal departure of these wells, transferring weight effectively while drilling and running tubulars can be very challenging. These challenges and the tools, techniques, and learnings used over the past 7 years to solve weight-transfer challenges in this remote environmentally sensitive area are discussed. Introduction The The West Sak field is part of the Kuparuk River Unit on the North Slope of Alaska (Fig. 1). The West Sak heavy-oil sands contain highly viscous, low-API-gravity crude (10 to 22ยฐAPI) at low reservoir temperatures [result of the extreme northern latitude and the shallow (3,000 to 4,000 ft) burial depth below 1,800 ft of permafrost in the overburden]. The reservoir has three primary sandstone targets, which are very-fine- to fine-grained single and amalgamated sandstone/siltstone beds. Geologic challenges while drilling include numerous fault crossings along the wellbore and random encounters with calcite-cemented spheroids, also known as concretions (Fig. 2). The concretions are much harder than the reservoir sand, having compressive strength of 25,000 psi vs. 500 psi for the reservoir sand. These concretions drill much more slowly than the adjacent sand, which accelerates wear on the bit, the bottomhole assembly, and the drillstring. This difference in hardness can cause the drill bit to deflect off the concretions, resulting in severe unwanted doglegs. Such doglegs make it difficult to maintain directional control, often increasing torque and drag, and can cause downhole-tool damage. West Sak Well Design The primary constraints on West Sak well design are as follows.The shallow vertical depth of the reservoir sands. The need for lateral azimuths to be only to the north or south (parallel to the natural faults) The need for precise lateral placements because of spacing requirements of the waterflood depletion plan The need to drill the laterals in-zone by use of real-time geosteering The need to avoid collisions with nearby wells drilled from the same gravel pad
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17383, "High-Mode-Number Vortex-Induced-Vibration Field Experiments," by J.K. Vandiver, Massachusetts Inst. Of Technology; H. Marcollo, AMOG Consulting; and S. Swithenbank and V. Jhingran, Massachusetts Inst. of Technology, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. This paper presents the initial results from vortex-induced-vibration (VIV) field testing of a long, flexible, model riser at a high mode number. The experiments were designed to gain understanding of the dynamic behavior of a long riser in uniform flow responding at mode numbers ranging from 10 to 25 in crossflow vibration. The observed reduced velocity and root-mean-square (RMS) displacement-response levels were reported. Mean values of the drag coefficient, Cd, and hydrodynamic damping derived from measured data were compared with calculated values from formulas commonly used in engineering design of offshore systems. Introduction Experiments at Lake Seneca, New York, took place in the summer of 2004. They were part of a larger testing program developed by Deepstar (a joint-industry technology-development project) for improving the ability to model and mitigate VIV. While these particular tests were focused on investigating uniform-flow conditions, a second set of tests designed for shear-flow conditions was performed subsequently in November 2004 and will be reported separately. The initial motivation for this field experiment was to improve the under-standing of VIV at high mode numbers. Most model testing has been conducted at low mode numbers (<10). Drilling and production in 1000- to 3000-m depths requires understanding VIV behavior at higher mode numbers but still short of infinite-length behavior. Experiment Description The Lake Seneca test facility is a fully equipped field-test station moored in calm, deep water. It was ideal for conducting a controlled test on a long, circular pipe in uniform flow. As Fig. 1 shows, the tests were accomplished by towing a vertical, composite pipe with a suspended bottom weight to produce the desired tension. The length, diameter, and tension of the pipe were chosen to permit crossflow excitation of up to the 25th mode. The maxi-mum speed possible with the system was limited by the maximum allowable deflection angle of the pipe. Typical towing speeds were approximately 0.3 to 1.1 m/s. The pipe was constructed in 30.5-m-long segments, which were joined together. Total pipe length was limited to 137 m by the depth of Lake Seneca. During the experiment, total lengths of 61.26 and 122.23 m were tested. Each 30.5-m-long section of pipe contained six evenly spaced triaxial accelerometers. The sampling rate was 60 Hz per accelerometer. The same serial network was used to sample the tension- and tilt-measuring devices very close to the top U-joint, connection. Two mechanical current meters measured towing speed; one was suspended underneath the towed weight, and the other hung over the side of the towing vessel. A load cell and tiltmeter were attached at the top of the pipe. This instrumentation allowed measuring the tension in the pipe and the top angle of inclination.
This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16630, "Bundle Hybrid Offset Riser: An Advanced Solution for Improved Riser-Tower-Systems Installability and Operability in Deep Water West of Africa," by Giovanni Chiesa, Saibos S.A.S.; Floriano Casola, Saipem S.A.; and Francois Regis Pionetti, Saibos S.A.S., prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
This article is a synopsis of paper SPE 68219, "Artificial Neural Network Models for Identifying Flow Regimes and Predicting Liquid Holdup in Horizontal Multiphase Flow," by El- Sayed A. Osman, SPE, King Fahd U. of Petroleum and Minerals, originally presented at the 2001 SPE Middle East Oil Show, Bahrain, 17-20 March.
This article is a synopsis of paper SPE 50140,"Deepwater-Riser Technology," by B.A. Carter, SPE, Hamersley Iron, and B.F. Ronalds, SPE, U. of Western Australia, originally presented at the 1998 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 12-14 October.
This article is a synopsis of paper SPE 38783, "Topside and Subsea Experience With the Multiphase Flowmeter," by Winsor Letton, Daniel Industries Inc.; Jon A. Svaeren, Framo Engineering A/S; and Gilbert Conort, SPE, Schlumberger Wireline and Testing, originally presented at the 1997 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October.
This article is a synopsis of paper SPE 36621, "Reservoir Compaction Well Design for the Ekofisk Field," by G.H. Schwall, SPE, Phillips Petroleum Co. Norway; M.W. Slack and T.M.V. Kaiser, Center for Engineering Research Inc., originally presented at the 1996 SPE Annual Technical Conference and Exhibition, Denver, Colorado, 6-9 October.
- Europe > Norway > North Sea > Central North Sea (0.26)
- North America > United States > Colorado > Denver County > Denver (0.24)
- North America > United States > California > San Joaquin Basin > Belridge Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
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Electrical heating of subsea flowlines is an heating for a more than 10-to 15-4-in.-thick Systems are available for use in conjunction the produced water, possibly restricting multiple flowlines, injection lines, electrical with bundles, pipe-in-pipe, and release to the sea. These systems - Long twin-flowline installations have the same installation, they may be bundled provide environmentally friendly high investment and operational costs. in a common carrier pipe or outer casing. Bundles are fabricated onshore in lengths or flaring for pipeline depressurizing. For a given subsea-flowline currently as deep as 1600 m.