Drilling offshore gas wells is a very challenging operation since it involves a high number of offshore rigs, mud losses into formation, well control and adverse weather conditions. All of which minimize the drilling efficiency on those wells with huge attendant cost, if no proper arrangement is put in place to mitigate these challenges. In the current setting where we can sometimes see rapid increase in offshore drilling operation challenges such as coping with severe drilling fluid losses into formations, the main challenge is to support offshore rigs with drilling fluid in a timely and seamless manner. As on-shore mud plant keeps up with a very high operational demand, launched and successfully implemented a new floating mud facility ("HUB") to improve supply and deliver mud materials and fluids to offshore drilling rigs. This floating mud and chemicals storage plant (HUB) spot successfully reduced transit times, minimized delays and nonproductive time previously experienced by the drilling rigs operating in offshore gas fields. These delays were due to late drilling fluid deliveries from the onshore mud plant and extended times to mix high-density fluids on the rigs. This innovative model guarantees significant savings in terms of saving mixing times, providing chemical storage capacity, consequently minimizing unnecessary rig site operations. There is also a significant reduction in environmental, health, safety, and risk exposure resulting in optimized shipping, distribution, back loading of drilling fluids, reduction in the utilization of supply vessels and rig resources, to support severe lost circulation or well control events. The HUB floating plant provides a full array of scalable fluids, mixing equipment and facilities to meet offshore operational requirements while eliminating the cost, extended lead-time, and specialized shipping. This plant encompasses a floating installation to mix and store drilling and completion fluids and chemicals. The HUB floating plant is equipped with twin mixing systems with the ability to mix and safely store more than 20,000 bbl of different fluid sets. It was recently utilized to mix high-density MICROMAX (manganese tetroxide) based completion fluid with excellent performance, despite the complexity of mixing over 2,500 metric tons (super-sacks), and still was able to handle different fluids seamlessly. This HUB is anchored within equal distance to the three largest gas fields. The reduction in delivery time is estimated to be 90% in both normal and emergency operations. Weighting materials and mud chemical storage capacity provides an additional platform to minimize rig deck utilization and drilling mud mixing construction capabilities, minimizing the huge coping pressure on the alternative onshore mud plant operations. Over the last 3 years of being in operation, the HUB floating plant has mixed more than 916,000 bbl of heavy mud and completion fluid, received over 19,000 bbl for storage, and stored up to 400,000 ft3 of barite, with more than 600,000 workhours, without any near misses, incidents, or accidents.

Some gas wells casing design call for running and cementing intermediate 18 5/8" casing string to cover weak formations (low pressure/losses) including hydrocarbon bearing formations. Some gas wells drilled in the offshore Arabian fields developed sustained Casing-Casing Annular (CCA) pressure problems, emanating from poor cement bond of the intermediate casings, especially the 18-5/8" x 24" casing annulus. This paper will examine the source of the problems, primary solutions, and the remedy for the problems. Primary cement is the first barrier to prevent sustained CCA pressure problems; from drilling through the production lifecycle of any well. Most of the wells experienced losses while drilling or cementing the intermediate casing; the current practice is to enhance the chances of a good cement job by installing an external inflatable packer with a circulation port (DV). This device splits the cement job into two stages and enables the second stage cement return to surface. In some completed gas wells, DV and cement barrier failure were recorded, which subsequently resulted in CCA pressure development. A solution was conceived to replace the 18-5/8" casing DV stage tool with a more reliable liner hanger (LH), in the most critical casing annulus CCA3 (18-5/8" x 24"), which has a higher risk of CCA development due to mobile hydrocarbon bearing formations covered behind the 18-5/8" casing. CCA3 pressure was reported in some wells. The shallow intervals were drilled, cased, and cemented, utilizing enhanced cementing practices and a DV tool in a 2-stage cement job. The LH alternative offers a good solution, but no technology was available worldwide to run the 18 5/8" liner and set inside 24" 201# casing, to avoid CCA pressure in this particular annulus size. The operating company collaborated with the lLH provider to develop the world's biggest LH, with metal-to-metal seal in the hanger and rubber seal barriers in the tie-back. The LH equipment was manufactured over a period of 6 months, deployed, and successfully field tested in five wells with no CCA3 pressure reported to date. The results of this LH installation will be discussed using case histories of recently drilled wells in the field, and compare results with some previous wells. For critical high rate gas wells with associated high construction cost, any technology applied to enhance well integrity, such as installation of the 18-5/8" LH, is considered an absolute necessity by the operator.