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This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 145854, ’Implementation of Next-Generation Intelligent Downhole Production Control in Multiple Dipping Sandstone Reservoirs, Offshore East Malaysia,’ by J.H. Chris Chen, SPE, N.M. Azrul, B.M. Farris, K.Z. NurHazrina, M.K.M. Aminuddin, and M.Y. Saiful Anuar, Petronas Carigali, and K.F. Gordon Goh, SPE, K.S. Premjit Kaur, T.K. Darren Luke, and A. Eddep, Schlumberger, prepared for the 2011 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 20-23 September. The paper has not been peer reviewed. A next-generation intelligent-completions system was implemented successfully in a complicated, highly dipping, multilayered sandstone reservoir with commingled production. In this multizonal production solution, the conventional surface-controllable downhole zonal flow-control valves are now integrated with data-surveillance gauges, intelligent sensors, and isolation packers into one completion joint, compared with the previous multijoints system (i.e., splicing of up to three joints per zone required conventionally). This single modulated joint system has reduced installation time substantially compared with conventional intelligent-completions installations. The risk of surface completions makeup damage before running in hole is also greatly reduced with fewer connecting components. Introduction The S field offshore East Malaysia consists of multiple dipping heterogeneous sandstone reservoirs with unconsolidated formation (Fig. 1). These multi-stacked reservoirs have an overall 40-m-thick oil column with margin-al oil initially in place (OIIP). A large gas cap (i.e., twice the OIIP equivalent) also exists. Because horizontal wells are recognized as one of the more productive development options in exposing wellbore to maximum reservoir con-tact and drainage area for recovery economics, the decision was made to drill 14 horizontal wells for the first batch of field development. This development option has reduced the number of well counts significantly while maximizing reservoir-drainage points, thus making the project economics for developing this marginal field greatly improved. Two of the 14 horizontal producer wells in this marginal field have been screened to apply the modular integrated-intelligent-completions system (IICS) to actively control and permanently monitor zonal inflow for optimal production. Developing a Thin-Oil-Rim Field Intelligently The downhole active-flow-control-solution application in the horizontal well was one of the selected strategies to complete wells in these complicated geology structures while enabling zonal-contribution adjustment and future zonal selectivity. This is an intelligent alternative zonal management option compared with the other passive version of the inflow-control-device applications in the same field. Out of the eight commingling producers analyzed, two oil producers (i.e., Well-A1 and Well-A2) were selected as potential candidates for the intelligent-completions design. The significant zonal-reservoir-deliverability contrasts for Well-A1 and Well-A2 proved suitable for an initial zonal-influx balancing and later reactive inflow solution.
- Asia > Malaysia (0.75)
- Asia > Indonesia > Jakarta > Jakarta (0.25)
- North America > United States > Wyoming > Carbon County (0.24)
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154386, ’Coiled Tubing Reduces Stimulation Cycle Time by More Than 50% in Multilayer Wells in Russia,’ by A. Yudin, SPE, K. Burdin, and D. Yanchuk, SPE, Schlumberger; and A. Nikitin, SPE, I. Bataman, A. Serdyuk, N. Mogutov, and S. Sitdikov, SPE, Rosneft, prepared for the 2012 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 27-28 March. The paper has not been peer reviewed. Traditionally, coiled tubing (CT) has had very limited service diversity in Russia. Its use has been mostly limited to wellbore cleanouts and nitrogen kickoffs after fracturing treatments. CT equipment and technologies were used to supplement stimulation operations in one of the world’s largest oil fields, Priobskoye, which has up to five separate layers per well. Conventionally, well completions at Priobskoye have involved complicated workover operations with tubing, packers, and wireline perforation after each stimulated layer. An average well with three layers took 30 days to complete. CT provided a significant improvement in completion efficiency, reducing the cycle time to just 10 to 12 days. Introduction Priobskoye is one of the world’s biggest oil fields. It is in the Khanty-Mansi autonomous region, and the Ob river divides it into two parts, the left bank and the right bank. Hydraulic fracturing is the main method used to increase production and recovery from the Priobskoye formations, and most new wells are stimulated immediately after drilling. Fracturing optimization has mostly evolved toward increasing the quality of hydraulic fractures. However, the Priobskoye field is a multilayer reservoir where separate fracturing treatments normally take excessively long times to complete. The standard completion method has consisted of a sequential approach of the workover crew perforating, the wireline crew running in tubing and packers, and the fracturing crew fracturing and pulling tubing and packers out of hole for each of the layers. That sequence takes a long time to complete the well, especially if the formation starts flowing naturally before the workover and wireline crews can manage the pressure properly to continue operations. Starting in 2008, CT fleets were employed to assist in the well-completion cycle with abrasive perforating and well-cleanout operations under pressure between the fracturing stages. The advantage of CT lies in its ability to perform the same sequence of operations significantly faster. In fact, the CT replaced both workover and wireline rigs, with the perforating performed with an abrasive material jetted through the nozzles of a special bottomhole assembly. A jet’s velocity and its focused flow create a hole inside the casing and a cavern inside the cement and the rock outside the casing (Fig. 1).
- Europe > Russia (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.54)
- North America > United States > Texas > Montgomery County > The Woodlands (0.25)
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154391, ’Reducing Operational Time, Fluid Usage, Hydraulic Horsepower, Risk, and Downtime: Targeted Fracs Using CT-Enabled Frac Sleeves,’ by Luis Castro, SPE, Thomas Watkins, SPE, Brian Bedore, SPE, and Robert Holt, Baker Hughes, and Greg Manuel, Pioneer Natural Resources, prepared for the 2012 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 27-28 March. The paper has not been peer reviewed. Unconventional reservoirs are an increasingly important part of the hydrocarbon production pool in North America. Because reservoir conditions typically require hydraulic fracturing for economical production, a significant amount of resources are focused on making the fracturing process faster and more efficient and on lowering its environmental impact. A novel technique to create targeted annular hydraulic fractures rapidly involves deploying an activation tool on coiled tubing (CT) to open fracture sleeves in a horizontal well. The new technology uses fracture sleeves that are activated swiftly using a CT bottomhole assembly (BHA). The system, already used in thousands of fracturing stages in Canada, speeds up the completion process, uses less fluid, minimizes risks, and reduces overall downtime. Introduction Unconventional reservoirs in the United States are commonly stimulated using what is known as the “plug-and-perf ” (P&P) method. This method requires a tubing-conveyed perforating (TCP) device run, typically on CT, for the first stage to open a conduit for pumping down the casing. The first stage of the fracturing treatment is then pumped down through the open perforations. Once completed, a composite plug and perforating guns are run on wireline to isolate the first fracture stage and to perforate intervals in the second stage (each interval is commonly referred to as a “cluster”). Running wireline in horizontal wells requires pumping fluid from surface to push the wireline BHA through the wellbore like a piston. After retrieving the wireline from the well, the subsequent fracture treatment is pumped. This process is repeated until all stages are completed. After the fracture spread moves off of the location, a CT unit is commonly brought in to mill the composite plugs and allow the well to produce. Although this method is the one most commonly used, it has drawbacks. P&P fracs are time consuming: They require numerous days on location to prepare the well (i.e., running the TCP device, known as a toe-shoot), complete all the stages designed for the fracturing treatment, and finally mill the plugs.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Gulf of Mexico > Ellenburger Formation (0.99)
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 145675, ’Statoil North Sea - Successful World-Record MLT Installation,’ by Johan Eck-Olsen, SPE, and Ove Andre Solheim, SPE, Statoil, and Morten Falnes, SPE, Halliburton, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September 2011. The paper has not been peer reviewed. Over the last decade, multilateral technology (MLT) has been widely used on several of Statoil’s licenses. In October 2010, the deepest-set sealed multilateral junction in the industry was installed at 6900-m measured depth (MD) in Oseberg South Well 30/9-F-9 AY tIY2. The main bore was drilled to total depth (TD) at 8583 m MD, and the 7-in. liner was run and cemented. After the liner perforation, the MLT operations started with the installation of a multilateral anchor packer to allow for installation of a latch interface assembly (LIA) and milling system. The lateral branch was drilled to TD at 8258 m MD, and a 5½-in. screen completion was run and dropped off into the 8½-in. open hole. A 6900-m-long upper-completion string with inflow-control valves was finally installed to allow for surface control of the two branches. Introduction The Oseberg South platform is located in the North Sea, 130 km west of Bergen, Norway (Fig. 1). Thirty-two wells are planned from the platform. Oseberg South field’s plateau production is approximately 5400 m/d (34,000 B/D). The sea depth is approximately 100 m. Well Geology Well 30/9-F-9 Yl/Y2 was planned to target the Upper Tarbert (UT) and the Middle Tarbert (MT) at the G-Central structure. The well was planned as an MLT well where the first branch (Y1) will produce UT oil and gas and the second branch (Y2) will produce MT oil. UT contains approximately 70% of the expected oil and gas reserves and generally consists of wave-reworked lower/upper shoreface siltstones and fine-grained sandstones with relatively poor reservoir properties (average values for porosity and permeability are typically on the order of 5–18% and 0.2–20 md, respectively). In general, the MT formation is subdivided into two parts: MT1 and MT2. MT1 is interpreted as near-shore depos-its, while MT2 was deposited in a more energetic tidal environment. The porosity is within the range of 12–26%, while the permeability varies from 50 to 2500 md. Well Design Because of the low permeability in UT, a long reservoir exposure is needed to recover oil. The reserves from the more-permeable MT are important for the well economy because of higher initial production rates. For this reason, a multilateral well combining production from MT and UT is considered as the optimal well concept. The selected multilateral system uses premilled-window technology, which does not generate any steel cuttings during junction construction because only aluminium is milled. An oriented nipple profile called a latch coupling is installed below the premilled window and is used to anchor the whipstock and completion deflector. At depth, the liner is oriented to position the premilled window on the highside before being cemented in place.
- Europe > United Kingdom > North Sea (0.81)
- Europe > Netherlands > North Sea (0.81)
- Europe > Denmark > North Sea (0.81)
- (3 more...)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Tarbert Formation (0.98)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Oseberg Formation (0.98)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 079 > Block 30/9 > Oseberg Field > Tarbert Formation (0.98)
- (3 more...)
This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 21758, ’Efficient Perforation of High-Pressure Deepwater Wells,’ by William Sanders, SPE, Carlos Baumann, SPE, and Harvey Williams, SPE, Schlumberger, and Flavio Dias de Moraes, SPE, Jonathan Shipley, Martin Bethke, SPE, and Scott Ogier, SPE, Petrobras, prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed. Thousands of perforating jobs are conducted successfully worldwide each month. However, for a small number of jobs, typically high-pressure deepwater wells, gun shock is a real and significant risk. The Cascade and Chinook projects presented the two largest deepwater high-pressure perforation jobs to date in the Gulf of Mexico (Fig. 1). These Lower Tertiary well completions have gross perforation intervals greater than 800 ft and downhole pressures higher than 19,000 psi. Perforating all intervals with long gun strings and then frac packing multiple zones in a single trip saves substantial rig time compared with performing conventional stacked frac-packed completions requiring multiple trips per perforated zone. Introduction Perforating several intervals in one run was required to complement a single-trip multizone frac-pack system in which all downhole packers, screens, and service tools are run at once and all zones are stimulated in a single trip. Planning, mobilizing, executing, and reviewing multizone perforating jobs at wellbore pressures higher than 19,000 psi and in water depths greater than 8,000 ft presents many challenges. Operational risks inherent to perforating multiple zones in a high-pressure deepwater environment were minimized by using a simple and reliable approach built on previous experience from high-pressure deepwater perforation jobs. Cost reduction is the main driver because of the very high daily cost of deepwater operations. With a one-way-trip time of 18–24 hours, eliminating just one trip in the well would save up to USD 2 million. Perforating three or four zones at once multiplies the savings. Planning Planning for these jobs began with evaluating the casing design configuration to ensure that the perforating bottomhole assembly (BHA) could be run in and retrieved from the well with no damage and that the casing could withstand the pressure requirements of the perforating operations.
- North America > United States (0.25)
- North America > Mexico (0.25)
- South America > Brazil (0.25)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Cascade Prospect > Block 250 > Cascade-Chinook Field (0.89)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Cascade Prospect > Block 250 > Cascade Field (0.89)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Cascade Prospect > Block 249 > Cascade-Chinook Field (0.89)
- (5 more...)