Ocean Drilling Program Leg 102 returned to Hole 418A 8 yr after it was originally drilled and retrieved a borehole water sample at a depth of ca. 350 m into basaltic basement. Chemical analysis for the major constituents and strontium isotopes indicates that substantial changes in the chemical composition of originally introduced surface seawater are principally due to diffusive exchange with surrounding formation waters. These changes include an increase in dissolved calcium and decreases in dissolved magnesium, sodium, and potassium, as well as in the 87 Sr/ 86 Sr ratio of dissolved strontium. Extrapolation of the data to zero magnesium yields dissolved calcium concentrations predicted by a diffusive exchange model, which is consistent with high dissolved calcium concentrations observed at other sites that show complete depletion of dissolved magnesium in the interstitial waters in sediments intercalated in basaltic basement.
Summary Ultralarge-diameter polycrystalline-diamond-compact (PDC)-bit drilling is a fast-growing cost-effective solution in high-tier deepwater drilling operations in the US Gulf of Mexico (GOM) where salt is encountered in the shallow part of the wellbore. Conventional design called for roller-cone (RC) (IADC Code 111-115) drill bits on positive-displacement motors (PDMs) in these ultralarge-diameter intervals. Cost savings on drilling fluid alone, in the form of rate-of-penetration (ROP) gains through the salt interval, has the industry trending to drill these riserless sections with the use of PDC drill bits on rotary-steerable-system (RSS) drilling assemblies. New robust high-torque-capacity topdrives, stronger drillpipe (DP) connections, larger-diameter RSS tools, and improved mud programs have all largely contributed to this step change in drilling performance. In addition, evolved bit and bottomhole-assembly (BHA) design, efficient operating parameters, improved hydraulics, and vibration-prediction modeling have all aided in the success of these runs. Although this emerging new trend reduces drilling times and associated cost, experience has shown there are multiple challenges that must be overcome to complete a successful run in a single trip. These challenges vary from well to well and include, but are not limited to, BHA steerability, rig-equipment limitations, efficient operating parameters, identification of both sediment and salt formations, hole cleaning and hydraulics, salt creep, drilling-fluid displacement, DP torque limitations, stabilization placement, lateral/ torsional BHA vibrations, and others. This paper will concentrate on the multiple aspects of ultralarge-diameter riserless PDC-bit drilling applications and the considerations that have been used to optimize them. Prior SPE papers and data from previous deepwater GOM case histories were heavily researched and scrutinized to support the conclusions provided within the body of this paper. Together with industry experience available, these findings have resulted in a set of defined recommendations, providing operators with a guide to justify a lower-cost-per-foot approach through the potential reduction of drilling time in these challenging applications.
Ultra-large diameter Polycrystalline Diamond Compact (PDC) bit drilling is a fast growing cost-effective solution in high-tier deepwater drilling operations in the U.S. Gulf of Mexico (GOM) where salt is encountered in the shallow part of the wellbore. Conventional design called for roller cone (RC) (IADC Code 111-115) drill bits on positive displacement motors (PDM) in these ultra-large diameter intervals. Cost savings on drilling fluid alone, in the form of Rate of Penetration (ROP) gains through the salt interval, has the industry trending to drill these riserless sections with the use of PDC drill bits on Rotary Steerable System (RSS) drilling assemblies. New robust high torque capacity top drives, stronger drillpipe connections, larger diameter RSS tools and improved mud programs have all largely contributed to this step change in drilling performance. Additionally, evolved bit and BHA design, efficient operating parameters, improved hydraulics and vibration prediction modeling have all aided in the success of these runs. Although this emerging new trend reduces drilling times and associated cost, experience has shown there are multiple challenges that must be overcome to complete a successful run in a single trip. These challenges vary from well to well and include, but are not limited to: BHA steerability, rig equipment limitations, efficient operating parameters, identification of both sediment and salt formations, hole cleaning and hydraulics, salt creep, drilling fluid displacement, drillpipe torque limitations, stabilization placement, lateral/ torsional BHA vibrations, and others. This paper will concentrate on the multiple aspects of ultra-large diameter riserless PDC bit drilling applications and the considerations that have been used to optimize them. Prior SPE papers and data from previous deepwater GOM case histories were heavily researched and scrutinized to support the conclusions provided within the body of this paper. Together with industry experience available, these findings have resulted in a set of defined recommendations, providing operators with a guide to justify a lower cost per foot approach through the potential reduction of drilling time in these challenging applications.
The Middle East has long been a pioneer in innovation in drilling and completion technologies for multilateral wells. It was here that the first1 multilateral tool (MLT) on coiled tubing was used to access and stimulate each openhole lateral in a trilateral well. Over the years, several2-4 applications of this and similar technologies have been made. In each instance, a conventional upper completion system was installed. In a multilateral well with a conventional upper completion and an openhole lower completion, there is no independent flow control from each lateral. Because of this, production is not optimized to account for differences in the production rate or reservoir quality of each lateral. For a well with an upper intelligent completion system (ICS), independent control of flow from each lateral is possible through the use of surface controlled flow control valves (FCVs). This feature addresses the shortcomings of the conventional upper completion mentioned earlier. The challenge in performing an acid stimulation of each openhole lateral in a well with an ICS is the inability to access any of the laterals after the ICS has been installed. Current technologies do not afford this option and designs in the pipeline do not have field proven applications. This paper chronicles a novel attempt at acid stimulating each openhole lateral of a trilateral well in a carbonate reservoir. It includes the installation of the ICS in the same well. The challenges, results, learnings and future courses of action are documented in what should provide a template for continuous improvement.
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