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Akhmetov, Marsel (Messoyakhaneftegaz) | Maximov, Maxim (Messoyakhaneftegaz) | Lymarev, Maxim (Messoyakhaneftegaz) | Malyshev, Yevgeny (Messoyakhaneftegaz) | Vasilyev, Roman (Messoyakhaneftegaz) | Glushenko, Nikolay (Messoyakhaneftegaz) | Rakhmangulov, Farit (Halliburton) | Frolov, Denis (Halliburton)
This article describes an experience drilling a multilateral "fishbone" well with eight sidetracks and contains geological substantiation of this technology from the production-increase point of view as well as actual results of the eight-lateral well start up and operation. For fishbone wells where each wellbore is a sidetrack from the previous hole, one of the fundamental drilling aspects is kickoff from the parent wellbore. This article is based on the analysis of 114 kickoffs in production wells of the East Messoyakha field where kickoffs with a rotary steerable system (RSS) and performance drilling motor (PDM) were determined beneficial. Additionally, strength analysis and hydraulic calculations for drilling of the longest fishbone at the East Messoyakha field with an extended reach drilling (ERD) factor of 2.95 are discussed. Further, this article highlights the main potential of this technology development and its limitations during a further massive application.
Lebedeva, Irina (Schlumberger) | Shakirova, Anastasia (Schlumberger) | Bravkova, Natalia (Schlumberger) | Famiev, Robert (Schlumberger) | Valshin, Oleg (Schlumberger) | Gaskov, Dmitriy (Schlumberger) | Shakhova, Anna (Schlumberger) | Sandy, Adam (Schlumberger) | Marushkin, Dmitry (Schlumberger) | Bochkarev, Vladimir (Rosneft) | Surmin, Vladimir (Rosneft-Sakhalinmorneftegaz)
This article provides the results of the first experience of running a wear resistant "push-the-bit" RSS (rotary-steerable system) for kicking-off at shallow depth in poorly consolidated sand formations.
According to the contractor's best practices, a shallow kick-off in sections with large diameters is performed using PDM (positive displacement motors) with a bent housing angle set up to at least 1.83 degrees. However, for wells in Odoptu field, which is located in the north of Sakhalin island, several specific features pose issues for the effective application of conventional directional drilling equipment to reach the geological targets.
A standard approach for drilling the 17 ½-in. section in Odoptu wells requires two runs:
Run1: A PDM with roller-cone bit are used to build the inclination from zero to 70-degrees in poorly consolidated sand formations
Run2: A conventional RSS with PDC (polycrystalline diamond composite) bit are used for drilling the tangent section.
The project team was challenged to reduce the well construction time by drilling this section in one run, however, there were technical concerns. Drilling with a PDM and roller-cone bit would not provide a high penetration rate in tangent section. Drilling with a conventional push-the-bit RSS might not provide the necessary DLS (dogleg severity) in the sandstone due to formation washouts. In addition, drilling in the sands exposes the drilling equipment to excessive erosion because of the high sand content in the drilling mud. Considering the average section length of 2000 to 3000 m of MD (measured depth), this wear could lead to damaging the costly drilling equipment breakdown and causing unplanned tripping operations.
The project team alongside the field operator decided to test a wear-resistant RSS for one typical well of the Odoptu-Sea field. As a result, the section was drilled in one run, achieving the planned DLS without any equipment erosive wear. In addition, the 17 ½-in. section of this well recorded the highest penetration rate of 58 m/h in the field. The implementation of a wear-resistant RSS saved 6 days of the total section time.
As gas fields mature and water production increases, understanding and managing the dynamic flow behaviour of the well and production system are critical for maintaining, and even optimising, production. This knowledge could be the difference between a successful and an unsuccessful attempt at re-starting a wet gas well after it is shut-in. When a well is in production, choking the well to optimise stable facilities operation and maintain water production within the water handling constraints of the facilities can be a fine line between achieving continuous stable production and the well ceasing production due to high liquid loading.
This paper describes the successful kick-off and unloading of two high-water producing gas wells within the operational constraints of the offshore facility. Transient multiphase flow models were developed for a platform well and a subsea well to simulate the wellbore flow dynamics during start-up. The models were tested over a range of values for parameters such as reservoir pressure, inflow performance and water gas ratio for different kick-off strategies but always honouring the facility's water surge management constraints.
The outcome of these simulations facilitated the development of tailored bean-up strategies for each high-water producing gas well, which provided a mechanism to engage with key stakeholders and demonstrate confidence in the execution of these strategies. Dedicated procedures were developed and subsequently executed successfully to re-start the two wells with the wells continuing to produce after kick-off and unloading, operating within the water surge management limits of the facility. Similar strategies are being developed for other high-water producing gas wells including those with material sand production.
This paper demonstrates strategic capability to realise additional value using dynamic modelling to kick-off mature high-water producing gas wells through proactive development of mitigation strategies which avoid production disruption.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189904, “Underbalanced Drilling With Coiled Tubing: A Case Study in Marginal Shallow Wells,” by Adam Miszewski, SPE, and Toni Miszewski, SPE, AnTech, and Peter Hatgelakas, Chuck Henry Energy, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed.
The complete paper describes a recent directional coiled-tubing drilling (DCTD) job completed for an independent operator in the Appalachian Basin. The objective was to access target zones identified as adjacent to a recently drilled vertical well using a lateral sidetrack. The project was ultimately successful in that a dry hole was re-entered and sidetracked to create a productive well.
The Economic Equation
The target of the project was to define drilling efficiency in terms of cost per production rate. This measure takes the initial production into account and ties together the ability of the driller to make hole in the direction required with the ability to select a productive part of the formation.
Recognizing that each stage of well construction can affect another, a multidisciplinary approach was adopted that included input from geology, geophysics, reservoir engineering, and drilling and completions engineering. Local experience with offset wells also was an important input, allowing for the fact that this experience was limited to vertical wells drilled with air or in an overbalanced condition.
The area chosen for the case study was in a well-understood area containing numerous offset wells with which to compare production and a known geology against which to plan the well. The wells typically do not exceed 2,500 ft in depth and were exclusively vertical. Four such wells had been drilled in the immediate vicinity in the previous year, three of which are currently on production at the time of writing at rates ranging from 10 to 25 B/D with varying levels of associated water production. Although one of the wells showed promise of production, the well turned out to be dry and the planned 4½-in. production casing string was not run and the well was not completed. The uncased well was chosen for the case study because it had the shortest payback period if it could be made to produce at a rate similar to those of neighboring wells. A 3D seismic survey of the area had identified a subsurface ridge that could be acting as a trap (Fig. 1). This ridge was selected as the target of the new well. A well path was planned that tracked approximately 15 ft below the top of the reservoir and along the top of the ridge, a depth low enough to access the reservoir but not so low that it might access the oil/water contact believed to be 40 ft below the reservoir top.
AbstractThe Stones project is an ultra-deepwater development located ~200 miles south of New Orleans in the Walker Ridge ("WR") protraction area of the Gulf of Mexico. This development is part of the frontier Paleogene outboard play in the Lower Tertiary Trend that targets the Upper and Lower Wilcox formations.The initial development (Phase 1) is planned for eight subsea wells directionally drilled from two drill centers with a production manifold located at each drill center. Dual 8″ flow lines will connect the two drill centers with dual 8″ risers connecting the drill centers to a Floating Production Storage and Offloading (FPSO) host. Oil is exported by shuttle tankers with gas exported through the Walker Ridge Gas Gathering System. Mudline pumps will be located at the first drill center. The Phase 1 production system is illustrated in Figure 1.The current field development plan incorporates optimizations based on information gathered during the early execution phase of the project. These optimizations were identified through multi-disciplinary integration with a focus on risk management and best-for-project decision making. This paper highlights the subsurface learnings and associated modifications to the field development plan to mitigate risk, lower costs and increase ultimate recovery.
Hussain, Sajjad (Schlumberger) | Dhaher, Karam Sulaiman (Schlumberger) | Bjoerneli, Hans Magnus (Schlumberger) | Blackburn, Jason (Schlumberger) | Monterrosa, Leida (Schlumberger) | Jakobsen, Tom (Statoil ASA) | Otto Monsen, Gisle (Statoil ASA) | Haaland, Sigurd (Statoil ASA) | Dahl, Johan (Statoil ASA) | Østensen, Ståle (Statoil ASA) | Fjelde, Kjell Kåre (University of Stavanger)
AbstractOld platforms are not well known for extended-reach drilling (ERD) operations mainly due to rig and hydraulics limitations. ERD wells demand robust rig capabilities, good hydraulics systems, and equipment reliability. In addition, the well profile, rotary steerable system (RSS), measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools, surveying, and new technologies are extremely important to the success in drilling an ERD well. RSS and drillpipe selection are important factors for hydraulics optimization. Surveying techniques are also important for time saving and improved efficiency. An ERD well in the North Sea Statfjord field was kicked off in the 17 ½-in. section from the openhole cement plug through a 50-m window between the 20-in. casing shoe and 13 3/8-in. casing stump, ensuring a smooth well profile and reduced doglegs compared to the whipstock window exit. The 17 ½-in. section was drilled and landed at a 79° inclination using point-the-bit RSS technology, and the 12 ¼-in. section was drilled in two runs as planned using the point-the-bit RSS withstanding more than 550 h down hole. The 9 5/8-in. liner was run and floated successfully in the ~6000-m section. Strict adherence to surveying techniques and quality control processes proved very helpful to meet Operator technical requirements. The 8 ½-in. section was drilled and landed on top of the reservoir with an inclination decrease from 88° to 35°. New MWD technology was successfully used in drilling the 6-in. section. These latest technologies as well as employing appropriate techniques help to drill ERD wells on aged platforms like those in the Statfjord field. This paper will describe the planning and execution phases of a challenging ERD well drilled in the Statfjord field.
Ab Hamid, Abdul Halim (Saudi Aramco) | Siregar, Verdy (Saudi Aramco) | Khalil, Mohamed E. (Saudi Aramco) | Ghazzawi, Ayman (Schlumberger) | Ashraf, Omar T. A. (Schlumberger) | Balka, Muhammad S. (Schlumberger)
Generally, deep gas workover/re-entry wells in Saudi Arabia are kicked off in the Sudair formation through a whipstock because the overlying base Jilh dolomite can flow with high pressure, which jeopardizes well control. Whipstocks are set deep in the 9 5/8-in. casing, after which the 8 3/8-in. and 5 7/8-in. holes are drilled to access the target Lower Carbonate and Sand reservoirs. Deeper kickoffs also avoid contact across the water-bearing Carbonate A, aiming for displacement across Carbonate B or C reservoirs. Isolation from Carbonate A is important for multistage fracturing completions as they are still not proven for the long-term isolation of water-bearing zones.
Regardless of the deeper whipstock setting, the high dogleg requirements exceed the capabilities of conventional rotary steerable systems (RSS). Conventional steerable motors with high-bend housing and 70 to 80% of the sliding mode of drilling has been the only option to achieve such high dogleg severity (DLS/100ft). Drilling medium-radius wells with a conventional motor assembly requires multiple runs, wiper trips to clean the hole, and multiple reaming trips before running the liner. These operations result in poor drilling efficiency due to slow penetration rates and bit trips.
A high build rate rotary steerable system (HRSS) was introduced as a solution for such challenges in the 8 3/8-in. and 5 7/8-in. sections. While the HRSS technology has been used before, this was the first time the HRSS kicked off vertically from a whipstock in Saudi Arabia or worldwide. The new technology allowed the kickoff point to be pushed further into the Sudair formation near the Sudair dolomite, reducing the risk from Jilh pressure and associated cost. The step change provided the option to slim the hole by eliminating the 8 3/8in. hole size, and kickoff was done in the 7-in. liner. Deployment of the HRSS allowed directly kicking off from a whipstock set vertically, eliminating the need for a dedicated steerable motor assembly run. Direct kickoff also meant eliminating the need for gyro tool for steerability, because conventional RSS tools could only be used outside the zone of magnetic interference, once sufficient separation from the mother bore was achieved. Consistent doglegs of more than 14°/100 ft were recorded; and the maximum dogleg was 17.44°/100 ft. Since then, this concept has been applied to other vertical re-entry wells and at an existing inclinations successfully in the 8 3/8-in. and 5 7/8-in. sections in Saudi Arabia and worldwide. The scope of the paper is limited to wells in Saudi Arabian deep gas wells only. The average rate of penetration (ROP) across this build section shows a 137% improvement over the ROP for conventional motor bottom-hole assemblies (BHA) for similar build sections. Eliminating the 8 3/8-in. section, avoiding the hazards of drilling in Jilh and Sudair formations, saving the motor trip to kick off from the whipstock, and improving ROP resulted in significant savings. This step change in drilling performance was realized by a thorough understanding of local drilling conditions and indepth analysis that enabled efficient execution.
Jasem Al-Saeedi, Mohammed (Kuwait Oil Company) | Al Fayez, Fayez Abdulrahman (Kuwait Oil Company) | Rasheed Al Enezi, Dakhil (Kuwait Oil Company) | Al-Mudhaf, Mishary N. (Kuwait Oil Company) | Sounderrajan, Mahesh (Kuwait Oil Company) | Subash, Jaikumar (Kuwait Oil Company)
The weighting up process for K-formate system consumed considerable time due to frequent plugging of hoppers with small particles of Manganese Tetaoxide. The selected intervals if gas prone should be avoided for drilling with these type of mud systems High corossion observed in MWD tools with K-formate mud. Compatibity should be ensured before lowering MWD tools Observed K-formate mud is sensitive to cement contamination as lot of gelled mud was observed on the setback area. In case of cement plug placement with such mud systems, it is advised to circulate out DP volume after placing the plug instead of flushing. It is recommended to use centrifuge when such sophisticated formate systems are to be used in a solid laden mud Testing and Coiled Tubing operations No testing of Najmah formation in open hole should be carried out when the kerogene interval exposed.
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.
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).
Increased water production is often the cause of reduced well performance, decreased hydrocarbon production, and/or killing the well. Water entry must be pinpointed before the remedial work to shutoff the water and to increase well productivity. A standard practice for shutting off the water is by running an integrated multiphase production logging tool, which is challenging in horizontal wells due to the high deviation, wellbore conditions, and multiple flow regimes. The diagnosis of this type of well becomes complicated when the horizontal well is dead.
In this paper, three field examples are presented on data acquisition (logging) in dead horizontal wells, with subsequent interpretation to pinpoint the water entry interval(s). The first well was completed with an inflow control device (ICD). An integrated production logging run during shut-in identified a leak with crossflow from the blank pipe to the open hole. The water source was determined to be a zone above the completed intervals. The second example is an open hole completion. The well flowed after nitrogen (N2) gas kickoff and the water entry was pinpointed from the toe section along with the oil profile. The third example is also a horizontal open hole completion. This well did not flow naturally, despite N2 lifting for 8 hours. Logging was conducted while injecting N2. Repeated passes yielded consistent results in pinpointing the water entry interval, and the water entry was identified also from the toe section.
These field examples demonstrated that integrated job planning and integrated interpretation are essential to opening new opportunities for diagnosing dead wells and providing solutions. Guidelines and recommendations for logging dead wells are now available for these types of logging conditions.