The operator has been active in Panna field for several years drilling a main horizontal and two laterals through a window milled in pre-existing 9–5/8″ casing. The laterals vary in length between 800m to 1600m, depending on the carbonate reservoir's constraints. However, interbedded formations with contrasting hardness had the potential to cause stick-slip and lateral vibration. Initially, the operator utilized RSS/MWD to geosteer the BHA within the target formation. However, previously chosen PDC bits caused severe lateral vibrations, stick slip and BHA whirl that resulted in multiple downhole tool failures. It appeared new PDC technology was required. An in-depth study revealed the BHA was exposed to severe stick-slip and lateral vibrations. There were also regular instances of BHA whirl and severe acceleration and deceleration caused by stick-slip. To enhance overall bit/BHA stability, a new-style 8–1/2″ PDC was implemented with innovative depth-of-cut control (DOCC) technology and enhanced stability features. BHA design was also reviewed and minor changes were implemented. The result was a significant reduction in stickslip, lateral vibration and BHA whirl. The new PDC/RSS set a new national Indian record for the longest 8–1/2" offshore section making 3956m of hole in a single run. The bit has since successfully drilled several multilateral drainholes in a single run proving the reliability of the new PDC design and enabling technology. The authors will present the vibration signature of a standard PDC versus the new one with DOCC. The authors will discuss proper RSS/PDC bit selection and demonstrate the benefit of DOCC/PDC on RSS when applied in high angle/horizontal wells. Introduction The Panna field1–3 is located in Arabian Sea about 95 km west of Mumbai, India (Figure 1). It is surrounded by other fields including Mukta, Neelam, Tapti and Bombay High. Together they constitute an important oil producing area of India. The Panna field is jointly owned by BG Exploration & Production India Limited (BGEPIL), who have a 30% holding, the Indian Government's Oil and Natural Gas Corporation Limited (ONGC) who maintain a 40% holding and Reliance Industries Limited (RIL) are partners with a 30% share. The field was discovered in 1977 and is estimated to have approximately one billion bbls of oil and 1.9 trillion cubic feet (tcf) of gas in place. Panna field produces from predominantly two carbonate reservoirs, including the upper A-zone (Oligocene) and lower B-zone (Middle Eocene). Overburden consists of argillaceous sediments of Chinchini, Tapti, Mahim and Bombay limestone followed by Alternations that lies directly on the A-zone reservoir (Figure 2). The Alternations horizon is between 70–100m thick and consists of thin interbedded shale and limestone formations of varying hardness. BGEPIL's current drilling campaign involves re-entering wells through a window milled in pre-existing 9–5/8″ casing to drill multiple fishbone laterals (Figure 3) through the reservoir section utilizing a rotary closed loop (RCLS) drilling system integrated with a resistivity, density and neutron porosity formation evaluation (FE) package (Figure 4). Application Challenges The initial horizontal wells in the Panna drilling campaign utilized steerable motors with LWD tools. However, this BHA experienced sliding difficulties that limited the extent of the horizontal reach. There were also drilling dynamics issues that caused severe tool damage on several occasions. Directional requirements/formation mineralogy while drilling the open-hole sidetrack in the 8–1/2″ horizontal section required the bit to deliver optimum dogleg severity without having an aggressive gauge as this may initiate hole spiraling and compromise wellbore quality and operational efficiency.
Utilising experimental data from 23 November to 8.December 1989. temperature and heat storage variations at Pune have been studied, based on 3 hourly observations.. pattern of penetration of .thermal wave within the soil has been examined and time of occurrence of maximum/minimum temperatures discussed for various depths. Temperature ranges in different layers have been theoretically computed and compared with those based on actual observations. Heat balance at various depths has also been presented and discussed.
The operator is active in drilling deepwater (DW) exploratory, appraisal, and development wells in the central and western areas of the Gulf of Mexico (GOM) where water depths exceed 4,000 ft. In this demanding application, a key step to a successful well is achieving high performance in the large-diameter surface sections of the well. This important segment can start a well ahead of the authorization for expenditure (AFE) or create setbacks and added unplanned costs. Increasing the rate of penetration (ROP) and improving wellbore quality are two essential components for reducing cost of the riserless sections of any deepwater well. Verticality must be maintained throughout the 26-in. large-diameter section to reduce casing wear and to ensure torque and drag remains minimal while drilling to deeper depths. The 26-in. hole section is drilled riserless and a high ROP generate additional savings by lowering the drilling fluid cost. The higher percentage of cuttings provides the additional equivalent mud weight so pump and dump (PAD) mud is not required. The increased ROP needs to be achieved with low vibration levels to avoid any bottom hole assembly (BHA) component failure that would necessitate an avoidable and costly round trip. The operator has previously drilled with 18⅛-in. hybrid bits in salt and sub-salt formations and has recognized the potential of hybrid bits and their ability to drill fast with stable drilling conditions. Several drilling records have been set in this hole size. Encouraged by the performance gains and better drilling efficiency of initial hybrid bit runs, the operator planned to reduce cost of their riserless drilling section in a batch drilling program in GOM. The 26-in. hybrid bit was implemented to batch drill three hole sections, each approximately 3,400 feet long. The operator was able to optimize the drilling parameters for each successive well due to growing confidence in the stable drilling environment. This enabled the drillers to increase the ROP and greatly improve time savings. The three intervals were drilled at ROP of 255, 308, and 379 ft./hr., respectively; breaking GOM field ROP records for each consecutive run with this operator. All three penetration rates have also surpassed the current world record ROP for this hole size. Subsequent 26-in. hybrid bit runs have established consistently higher ROP and have proven to be a significantly better solution when compared to polycrystalline diamond compact (PDC) bits. This paper presents the details of the performance improvements achieved through the use of large-diameter hybrid bits, compares the drilling efficiency of large-diameter PDC and hybrid bits, and discusses some important design aspects of the hybrid bit that deliver stability and steerability.
Deepwater wells routinely use concentric reaming devices in the bottomhole assembly (BHA) to lower the equivalent circulating density (ECD). In Gulf of Mexico (GOM) applications, concentric reamers are frequently used and are positioned approximately 100 to 150 feet behind the pilot bit to address formation evaluation and other operational constraints. This distance between a drill bit and the concentric reamer poses bit–reamer synchronization challenges, especially while drilling interbedded formations, where the bit could drill a softer formation while the reamer is placed in a harder formation or vice versa. This situation causes fluctuations in the compressive load at the bit and reamer. Cutting element damage often results from overloading, leading to a premature and costly trip. In many cases, the pilot bit or reamer could be deprived of the optimal compressive load to cut the formation, resulting in lower-than-expected penetration rates. Inadequate and fluctuating compressive loads at the bit or reamer often trigger unsustainable vibrations. Efforts to address the bit-reamer matching issue are ongoing in the industry, and managing the aggressiveness of pilot bit and reamer is frequently used as a potential solution. Although modelling programs are extensively used during the well planning process, a lack of specific guidelines continues to exist in the industry. Hybrid bits, which combine polycrystalline diamond compact (PDC) and tungsten carbide insert (TCI) rolling cutter elements, have been widely and successfully used in GOM. These bits offer higher drilling efficiency because of their dual cutting elements and balanced aggressiveness. The results of 18⅛-in. hybrid drill bit usage with a concentric reamer provided encouraging results and offered a potential solution to the bit-reamer synchronization issue. Using real-time downhole data, this paper evaluates and compares bit and reamer load distribution, drilling mechanics of PDC and hybrid bits, and provides valuable analytical insights on successful application of hybrid bits to address the issue of bit-reamer synchronization.
Torsional instability in a drilling system is a significant challenge that limits performance. In its extreme form, known as stick-slip, the drillstring stops and restarts, exposing its downhole equipment to extreme forces that can lead to failures, unintended trips, and escalated operation costs. Torsional instability can also trigger lateral dysfunctions and whirl, creating further risk of bit and bottomhole assembly (BHA) failure. The risk of torsional dysfunction is heightened in applications involving concentric reamers and long drillstring, high-angle wells. The correlation of polycrystalline diamond compact (PDC) bits with torsional dysfunction is well known, and different approaches have been suggested to address the issue. The fixed depth of cut control (DOCC) approach, which is commonly used to address the issue, limits the PDC bit and formation engagement at a pre-determined ratio of rate of penetration (ROP) and drillstring RPM. However, this approach has an uncertain success rate when drilling conditions change. To address the challenge of torsional dysfunction while drilling a directional well with a 12¼-in. pilot bit and a 14½-in. concentric reamer, a self-adaptive DOCC technology was deployed in a deepwater well in the Gulf of Mexico (GOM). The self-adaptive DOCC technology automatically adjusts the depth of cut engagement threshold as drilling conditions change, eliminating the manual parameter adjustment required at surface to manage torsional dysfunction. The application of self-adaptive drill bit technology in the target well yielded excellent results, and the section was completed with a single bit/BHA run. Ninety-eight percent of the interval was drilled with no torsional dysfunction. The drillstring whirl was negligible, and 99% of the interval was drilled without lateral vibration. Eliminating harmful dynamic dysfunction significantly enhanced drilling performance and increased the ROP by 57% over the best PDC offset run. The dull bit condition was very encouraging; the bit displayed very low wear and no undesired impact damage, showing the effectiveness of the technology. This paper uses real-time drilling dynamics field data measured downhole and demonstrates the effectiveness of self-adaptive DOCC technology for drilling performance improvement in deepwater directional well where torsional dysfunction continues to remain a significant challenge and could be a performance limiter.
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