This article presents results from the Controlled Mud Pressure (CMP) field trial that encompassed well control on a rig equipped for dual gradient drilling. The tests were carried out after successfully drilling three laterals with a partly evacuated riser with a controlled mud level. The paper focus on analysis of the results to quantify the ability to: detect in-/out-fluxes of gas and liquid; circulate out gas with both an open and closed annular preventer; suppress migration of drilled gas into the evacuated part of the riser during drilling.The CMP test objective is to verify the ability of the CMP equipment to detect and controllably circulate out simulated influxes. Five tests are documented: one with liquid in-and out-fluxes introduced through the choke line using the cement pump, and four with gas introduced through the drill string. Nitrogen was used to emulate gas kicks, which were circulated out of the well with both an open riser and with a closed annular preventer and a dedicated return line, connected to the subsea pump module and a topside-mounted choke. To address the challenge with drilled gas accumulating in the evacuated part of the riser, small portions of Methane were injected into the drill string while circulating. Gas sensor readings at the shakers and in the flow-line were used to monitor gas concentration in the mud and above the mud mirror, respectively.The main findings from the field trial are: volume imbalances due to abrupt changes in flow rate into the well are quickly detected; it is possible to circulate small gas kicks out of the well through the subsea pump module and dedicated well control equipment when closing in the well with the annular preventer, given that the pump handles a mixture of mud and gas, and can withstand a high differential pressure to sea; it is not advisable to vent large gas kicks into the evacuated part of the riser without closing the blowout preventer (BOP). In addition, gas migration velocities in water-based mud with varying flow rates and gas content are reported.The article directs attention to deep water well control using specialized equipment for dual gradient drilling. It also contains valuable analysis of field trial results, which contribute to the understanding of gas migration, and the possibilities and restrictions, introduced with dual gradient drilling.

This paper describes the preparation and operation for the first use of a riserless mud recovery (RMR) system on the top-hole section of a well in the Gulf of Mexico. The material includes pre-well engineering and preparations including hydraulic analysis, pre-job vessel inspection, construction of new equipment, installation, pre-well planning decisions, and rationale for decisions. In addition also discussed are benefits including improved wellbore quality due to use of an engineered drilling fluid, logistics savings from reduction of drilling fluids, and minimized environmental impact. The paper also includes descriptions of equipment installation and testing onboard the drilling vessel operations during drilling, problems encountered and lessons learned from the operation. A description of all equipment is included in the paper along with specifications and operation parameters. An RMR system has application in the top-hole drilling of oil and gas wells. Using conventional methods, drilling fluid pumped down the drillstring during operations flows out onto the sea floor; this is often referred to as " Pump and Dump??. RMR collects the mud at the mud line and pumps the fluid back to the rig where it is reconditioned and reused. It allows the use of engineered drilling fluids and has possible applications for all offshore drilling. RMR was deployed on a dynamically positioned vessel, and successfully used to drill the 26-in. hole section. Drilling fluid recovered from the mud line back to the drillship was processed and reused, resulting in significant reduction in the volume of mud required for this top-hole section. RMR reduced costs through savings in drilling fluid and improved well construction. RMR is applicable to the drilling of top-holes in the entire Gulf of Mexico. It has significant potential to reduce top-hole drilling costs, eliminate casing stings, extend casing shoe depths, drill through and past problem formations and improve the wellbore by eliminating washouts and shallow hazards. Introduction Operators continue to explore and develop fields at increasing water depths. In certain offshore areas where younger sedimentary rocks are deposited, there is often a very narrow margin between formation pore pressure and fracture pressure that creates tremendous drilling challenges (Rocha and Bourgoyne, 1994). The solution to this narrow operating window is to develop techniques that extend the casing setting depths more efficiently. The use of a riserless drilling technique, dynamic kill drilling (DKD), has been instrumental in successfully pushing the casing depths deeper in deepwater applications (Johnson and Rowden, 2001). The DKD methodology employs the dual gradient drilling concept, consisting of the seawater hydrostatic above the mud line with the ability to vary the hydrostatic below the mud line by drilling fluid weight variations. This functional control of the drilling fluid density is tremendously advantageous while drilling shallow gas or water flows from over-pressured formations where large washouts, caves, formation compaction, and collapse could occur (Pelletier et al., 1999). This technique has been repeatedly employed in challenging deepwater projects where the initial upper hole sections were extended to obtain the required leak-off tests (LOTs).

A high-speed drilling system has been developed which drills medium strength rocks at rates up to 1000 ft/hr (328 m/hr). This system uses special motors to operate high-pressure PDC bits at pressures up to 10,000 psi (69 MPa) and at speeds of 800 to 1000 RPM. High drilling rates were achieved due to the high rotary speeds and the use of PDC cutters to remove the rock ledges left on the hole bottom by the high-pressure jets. Introduction In the late 1960's and early 1970's, Exxon and Shell conducted field tests with high-pressure diamond, drag and roller bits operating at pressures of 10,000 to 18,000 psi (69 to 124 MPa). These tests were conducted with conventional drill muds and modified rotary rigs operating at rotary speeds of 50 to 100 RPM. These high-pressure bits drilled many formations 2 to 3 times faster than rotary bits, but they were not commercialized due to difficulties in pumping the high-pressure fluids. In the late 1960's, Gulf conducted extensive field tests with abrasive jet drills which circulated viscous muds containing 6-percent steel shot (20/40 mesh) at pressures of 8,000 to 15,000 psi (55 to 103 MPa). The abrasive pressures of 8,000 to 15,000 psi (55 to 103 MPa). The abrasive jet bits drilled hard formations in West Texas 4 to 20 times faster and 3 to 7 times further than conventional roller bits. They were not economical due to 1) severe erosion problems with the abrasive fluids, and 2) excessive pump problems with the abrasive fluids, and 2) excessive pump horsepower requirements (3,000 to 10,000 hp). Although these systems were not economical, the tests demonstrated that high-pressure jet bits could drill oil-field rocks at high rates. Another important development relating to high-speed drilling during the 1970's was the development and implementation of man-made polycrystalline diamond cutter (PDC) bits. These bits drill many formations 2 to 3 times faster than roller bits when used on high-speed drilling motors (400 to 1000 RPM). In 1984, Maurer Engineering undertook the development of a high-speed drilling system to drill 8-inch (203 mm) diameter holes in medium strength rocks (5,000 to 10,000 psi; 34.5 to 69 MPa) at rates of 500 to 1000 ft/hr (164 to 328 psi; 34.5 to 69 MPa) at rates of 500 to 1000 ft/hr (164 to 328 m/hr). Conventional rotary rigs can drill these rocks at 50 to 100 ft/hr (16 to 33 m/hr) and downhole motors at 100 to 300 f t/hr (33 to 98 m/hr), so a new drilling system had to be developed to drill these rocks at the very high penetration rates. This goal was accomplished by developing a new down-hole motor which operates at high pressure (10,000 psi) and at high speeds (400 to 1000 RPM). Extensive laboratory tests confirmed that drilling rates of 500 to 1000 ft/hr can be achieved in medium-strength rocks with 8-inch diameter high-pressure (10,000 psi) PDC bits operating at 800 RPM. 2.5 INCH BIT TEST'S The initial tests were carried out in 1984 using the 2.5-inch (63.5 mm) diameter high-pressure PDC bit shown in Figure 1. This bit contained six 0.07-inch (1.78 mm) diameter nozzles. Figure 2 shows the 2.5 inch high-pressure bit operating at 10,000 psi in the Drilling Research Center, Inc. drilling test facility in Houston, Texas. This bit drilled at rates in excess of 1000 ft/hr in Berea sandstone as shown in Table 1 and Figure 3. A conventional PDC bit (80 psi; 0.55 MPa) operating on a rotary rig at 100 RPM drilled Berea sandstone at 90 ft/hr (29.5) m/hr). Increasing the rotary speed of this bit to 1000 RPM with a downhole motor increased the drilling rate to 260 ft/hr (85.3 m/hr). Equipping the same bit with high- pressure nozzles (10,000 psi) and operating it at 1000 RPM with a new high-pressure motor increased the drilling rate to over 1000 ft/hr (328 m/hr).

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This paper reports results on a well control study for a Joint Industry Program (JIP) to develop a Dual Gradient Drilling (DGD) system called Controlled Mud Pressure (CMP). Conventional well control may not be possible when using dual gradient systems, because a choke line full of heavy mud may fracture the formation, thus making well control a major obstacle to implementing DGD offshore. The project developed several well control methods and one was selected for Field Testing, after a risk assessment process with the Operator. The selected procedure is a variation of "Driller's Method". The project also proved that "Partial Dual Gradient Drilling" could be implemented within boundaries of conventional well control, i.e. "Driller's Method" with the DGD system isolated. A two-phase dual gradient well control simulator was developed for the actual field trial setup. The simulator duplicates planned offshore experiments, including injection of Nitrogen gas "kicks". The simulations show that the DGD system has the capability of detecting formation influxes early, keeping them small so they can be circulated out in dual gradient mode, and the ability of DGD to increase kick margins and thereby improving safety. This work has application to subsea pump based DGD systems where returns exiting the well are pumped back to the drilling vessel. DGD has application to improve safety and deepen casing shoe depths in deepwater wells. The simulations show how the system can detect formation influxes or losses, and maintain a safe pressure profile, allowing drilling where conventional principles will not work. They also show how the bottom-hole pressure variations are kept small as influxes are pumped out of a well using a modified driller's method. A planned field trial will verify the simulation results enabling further development of the DGD System. In many cases, conventional drilling does not permit the economic completion of deep wells in deep-water basins. New technologies need developing to facilitate this drilling. DGD is one technology with significant potential, and has undergone substantial development to allow introduction into these drilling situations.