In Arctic offshore areas where exploration and production of hydrocarbons may occur, a substantial portion lies in water depths less than 50 meters. Currently there are no MODU's which can drill all different well types, production and exploration, over a wide range of water depths from 10 m to 50 m, ice conditions, and facilitate alternative development plans, using wellhead platforms. ConocoPhillips Company, in cooperation with Keppel, Offshore and Marine and Technology Centre, have developed a basis of design and specifications for a Self elevating Arctic Mobile Offshore Drilling Unit (MODU) for use in these water depths capabilities to drill a wide range of wells. Economics require that a new build Arctic MODU be highly productive and operate nearly year-round. The Basis of Design and specifications result in a MODU that would have a wide range of application, be highly productive, and make alternative field development concepts viable. The focus of this paper is to detail major items that impact the size, weight, and configuration of an Arctic MODU. This will result in a conceptual unit design that will be used in determine ice loads, layout, and structural design of the Arctic MODU.

A casing drilling pilot program was conducted in the San Juan basin to determine if lost returns could be eliminated in a depleted coal formation. The pilot program proved that casing drilling can mitigate lost returns drilling through the coal and can be made economic in a low cost environment. The reduction in the amount of fluid lost should result in less damage to offset producing coal wells, resulting in higher ultimate recoveries. Development costs may also be reduced, by replacing directional wells drilled to avoid lost return zones, with lower cost vertical wells. A total of six wells were drilled with non-retrievable casing drilling bits. Two wells were drilled using a casing drilling bit on drillpipe (DP). Based on the bit performance four other wells were drilled with casing. Three wells drilled through the coal and had losses that were eliminated with casing drilling. One well experienced a bit failure and did not drill into the coal. The pilot program was completed with significant learnings. Losses were healed in the coal. A non-retrievable casing drilling system successfully drilled to the intermediate casing point without a trip. The bit design was changed significantly and resulted in 54% improvement in drill rate with instantaneous rates of penetration (ROP) similar to traditional polycrystalline diamond compact (PDC) bits. The initial casing design was modified to decrease vibration, and eliminate fatigue after a failure was experienced. The casing drilling bit was successfully drilled out with an air hammer and hammer bit. Other tools and techniques applied during the pilot program included cement stage tools, foam cement, and aerated fluids to reduce the equivalent circulating density (ECD) and to improve ROP. Introduction Background The San Juan basin is located in northwestern New Mexico and southwestern Colorado in the USA. The majority of the basin is in northwestern New Mexico (Fig. 1).

During offshore oil and gas well decommissioning, well casing cement bond verification is frequently a critical initial step of well plug and abandonment (P&A) operations. This is done to determine the isolation between geological intervals. To acquire the essential data, conventional cement bond logs (CBLs) and ultrasonic imaging logs require unimpeded access to the casing annulus. Consequently, the production tubing needs to be removed from the wells. These operations are costly as they require securing the well and removing the tubing with an offshore rig, in some cases a mobile offshore drilling unit. If cement integrity or isolation could be determined without removing the production tubing, operational time and costs would be significantly reduced. Hence, multi-string cement bond evaluation for isolation verification without pulling the tubing has been desired by the oil and gas industry for many years. The innovation described in this paper, consisting of a novel methodology and an associated logging apparatus, leads to a new technique that can evaluate cement bond or isolation around the casing through the production tubing. The acoustic energy emitted and received by a logging tool inside the production tubing travels through tubing and the surrounding annulus to determine the attenuation caused by the material behind the outer casing. The smaller bonding signal, challenged by the dominating signal from the tubing wall, is then successfully identified through unique frequency domain signal processing. The accuracy of a multi-string logging technology has been verified by extensive offshore field tests in Southern North Sea. Side-by-side comparisons with conventional CBL and ultrasonic logs after the tubing is pulled out have been conducted. The field tests also demonstrate the multi-string logging technology is applicable to all typical casing and tubing weight or size combinations and provides quantitative assessments on isolation conditions of wells through the production tubing.

Jack-up drilling units have been used in Arctic open water seasons and areas with very limited icebergs. They have not been used in areas where significant sea ice can move in with high concentrations. These areas have typically been drilled using a floating mobile offshore drilling unit (MODU) although the water depths are typically less than 50 meters. Floating MODU"s in shallow water depths can have significant downtime due to the limited offset in shallow water and typically require placing the well control equipment in a seabed cellar. In these areas, jack-ups can improve both operational safety and efficiency as they have limited weather related downtime.Several studies were carried out to determine the feasibility of using a modern high capacity jack-up MODU"s for exploratory drilling in these areas. This paper will review the studies including structural analysis, ice management approaches, and well control considerations. It will also review the further potential of jack-ups in the Arctic.Studies showed that using a jack-up drilling unit is feasible in shallow Arctic seas such as the Chukchi Sea when coupled with an effective ice management system. The jack-up unit has sufficient ice resistance to withstand interaction with thin early winter ice. Specific designs of jack-ups are capable of taking impact forces from thicker ice floes that may occur during an ice incursion event during the open water season. The maximum floe size during an ice incursion is limited and controlled by the associated ice management system. An ice management system was developed using a combination of satellite imagery, ice management vessels, and ice alert procedures. This system was determined as effective in managing ice to allow the jack-up to operate in the Chukchi Sea area.Environmental and personnel safety is enhanced by the use of a Pre-positioned Capping Device, an in place source control device. The device is independent from the rig"s well control system and provides another level of protection in additional to the jack-up"s BOP.The conclusion, based on structural and ice management studies, is that modern high capacity jack-up drilling units can be an effective way to drill wells during the open water season in shallow waters of Arctic seas including areas in to which sea ice can move. The studies also show that there is potential for use in other areas.

Remote Arctic onshore exploration can be very costly, frequently exceeding the cost of a deepwater Gulf of Mexico well. This paper reviews the reasons for these high costs and a possible combination of new proven technologies and rig designs to significantly reduce these costs Logistics, mobilization, demobilization and a limited drilling season are factors that combine to cause high costs. Operation time requirements and the short drilling season normally results in a rig drilling one well per season. A significant reduction in exploration final hole size is the primary driver in reducing costs as this leads to a major reduction in rig size. Downsizing does not limit well evaluation due to recent developments in downsizing evaluation equipment. The majority of the required information can be obtained with this finder well or "scratch and sniff" approach. This downsizing allows the use of an innovative rig design; hybrid coil tubing drilling unit; that has significantly reduced mobilization and demobilization times. The reduction in drilling and mobilization/demobilization time can result in one rig drilling multiple wells in the drilling season. Combining new technologies, such as casing drilling and coil tubing drilling, reduces drilling time and allows the hybrid coil tubing rig to drill deeper. Casing drilling and coil tubing drilling are areas where ConocoPhillips is an industry leader. A significant reduction in exploration cost is predicted, estimated at 50%. Introduction ConocoPhillips (COP) has significant Arctic onshore exploration acreage in Alaska, Canada, and Russia (through a (jJoint vVenture with OOOLUKoil Naryanmarneftegaz with Lukoil). The majority of the exploration prospects are far from existing infrastructure, 50 to 200 miles. Most remote exploration, greater than 570 miles from infrastructure, has been done using snow roads. Building ice roads for longer distances is not cost or time effective. The rigs are transported using low ground pressure vehicles, such as sleds, bull dozersRolligons, RolligonsTM (a), QuadTracsTM (a)Quadtracs, sleds, etc. In some cases conventional transportation equipment can be used but this requires highly packed snow roads. This delays mobilization until the packed snow essentially turns to ice and can accept a higher bearing pressure. The well pads are typically ice, built using water from local lakes. When drilling is completed and the pad melts there is no damage to the tundra. In Russia, sand or gravel pads, are built even for exploration wells. The rigs used are typically rated to more than 20,000 feet with 5-inch drill pipe. The rig components can be broken down to 8 ½ feet wide by 8 ½ feet tall and 50 feet long, maximum weight less than 50,000 lbm. This results in approximately 100 loads for the rig and 50 loads of associated equipment. Rigs in the Russian Arctic have large component pieces and are moved by skidding them on sleds1. Erection of the rigsequipment requires using cranes. This workErection is subject to weather related delays, blowing snow and low temperatures that shutdown crane operation. Thirty 30 days is a reasonable estimate of the time required to mobilize this type of rig. Stacking rigs close to the exploration well site has been done previously to reduce mobilization time. This however has not been very successfully in decreasing mobilization and rig up time. Rig moves in the Russian Arctic can take over three (3) months. Although rig components are large all the primary and auxiliary piping, ducting, insulation, etc. are fabricated onsite. Arctic conditions at initial mobilization are typically no daylight and low temperatures. During the Alaska 2006 season the time period, late January to early February 2006, had a minimum temperaturee of -55°F and a maximum temperaturee of -15°F. The average temperature during this time period was -35°F. At temperatures below -35°F all crane operations are essentially shutdown as booms may experience brittle fracture.