fax 01-972-952-9435.References at the end of the paper. AbstractDrilling and cementing operations in certain subsalt wells in the Gulf of Mexico (GOM) and other areas have long challenged operators and contractors. These wells have thick, deep salt formations with shear zones just above and below the salt, resulting in high unexpected costs during drilling. Such formations are often referred to as rubblized or disturbed shale zones. One theory proposes that, during geologic periods, the movement of adjacent salt formations induces shearing stresses that cause deformation, brittle failure, and fracturing in the surrounding shales. Costly drilling problems in these zones are primarily caused by the narrow margins between pore and fracture pressures that result in severe lost circulation, hole instability, and high-pressure kicks. Some of these wells also exhibit uncontrolled gas flows and underground water flows. Many GOM deepwater blocks and shelf blocks have massive salt structures and potential hydrocarbon reservoirs, but the trouble costs and difficulties associated with drilling these wells have forced operators to plug and abandon some wells and completely avoid others.Conventional lost-circulation and hole-stabilization treatments have been minimally successful in many subsalt wells. However, new wellbore-stabilization and cementing programs designed for subsalt wells can help ensure well control and integrity during drilling and production operations. This paper provides information for helping to improve subsalt drilling operations and lower well-construction costs. In addition, the failures and successes of lost-circulation treatments performed during drilling operations in shear and salt zones will be explained. Primary cementing operations that help provide cost-effective zonal isolation and well integrity in these zones are presented, as well as best practices and proposals for cementslurry design and mud displacement. Laboratory studies and cost comparisons that help justify replacing traditional materials and procedures with these cementing programs are also presented.

fax 01-972-952-9435.References at the end of the paper. AbstractDrilling and cementing operations in certain subsalt wells in the Gulf of Mexico (GOM) and other areas have long challenged operators and contractors. These wells have thick, deep salt formations with shear zones just above and below the salt, resulting in high unexpected costs during drilling. Such formations are often referred to as rubblized or disturbed shale zones. One theory proposes that, during geologic periods, the movement of adjacent salt formations induces shearing stresses that cause deformation, brittle failure, and fracturing in the surrounding shales. Costly drilling problems in these zones are primarily caused by the narrow margins between pore and fracture pressures that result in severe lost circulation, hole instability, and high-pressure kicks. Some of these wells also exhibit uncontrolled gas flows and underground water flows. Many GOM deepwater blocks and shelf blocks have massive salt structures and potential hydrocarbon reservoirs, but the trouble costs and difficulties associated with drilling these wells have forced operators to plug and abandon some wells and completely avoid others.Conventional lost-circulation and hole-stabilization treatments have been minimally successful in many subsalt wells. However, new wellbore-stabilization and cementing programs designed for subsalt wells can help ensure well control and integrity during drilling and production operations. This paper provides information for helping to improve subsalt drilling operations and lower well-construction costs. In addition, the failures and successes of lost-circulation treatments performed during drilling operations in shear and salt zones will be explained. Primary cementing operations that help provide cost-effective zonal isolation and well integrity in these zones are presented, as well as best practices and proposals for cementslurry design and mud displacement. Laboratory studies and cost comparisons that help justify replacing traditional materials and procedures with these cementing programs are also presented.

This paper presents a technique for cementing a 20- or 24-in. OD conductor pipe offshore, in deep water, in the presence of pressurized water flow, which constantly threatens to wash cement away from the well bore. At 1,000 ft below the mudline (BML), a highly pressurized flow of water prevents the use of conventional cementing methods and products to cement conductor pipe. The principal challenge to slurry designers is the narrow window of slurry density that will work in the conditions described in this paper. For example, the fracture gradient of the formation might limit the cement slurry weight to only ll ib/gal, while formation pore pressure will wash out any slurry of less than IO.5lb/gal. The conductor pipe featured here was cemented with a lightweight, foamed slurry with good compressive strength; the compressible nature of the foamed slurry helps control water flow. A single cement dry-blend can be used for all densities needed. The method described in this paper includes the use of three key fluids:Foamed drilling fluid sweeps. The well bore for the conductor pipe is drilled with straight seawater as a drilling fluid, so on a regular basis, 200-bbl stages of foamed sweeps are used as drilling fluid to bring cuttings out of the well bore.Settable spotting fluids. These fluids have low gel strength, and are composed to provide fluid-loss control. The settable fluid is used because it will set in 7 to l0 days if it is bypassed by the cement slurry pumped. Heat of hydration yielded by the cement slurry speeds setting time significantly.Foamed cement slurries. The combination of settable spotting fluid and cement slurry provides good zonal isolation of the water-flow interval. This paper presents and illustrates the procedures necessary to cement a conductor pipe through a zone of high-pressure water flow successfully. Introduction Operators in offshore areas require special techniques to cement geologically young formations that occur less than 2,000 ft BML and are not well consolidated. Makeup of these formations is largely a product of erosion from the continental shelf (Figs. I and 2, Page 6 and 7). Consequently, conditions there hold the potential [or (I) overpressured water flow formations, and (2) the existence of weak formations that can fracture and cause loss of cement/mud returns to the sea floor. Some water sands may be overpressured so that they cause saltwater to flow into the cement sheath (Fig. 3, Page 7). Prevention of this flow is critical, since remedial steps to stop flow and repair damage are far more expensive than proper preventive steps. Containment of the overpressure problem is further complicated by weak (low fracture gradient) zones that can fracture and cause loss of mud and cement returns. The challenge presented by this situation is to cement the conductor casing annulus in an overpressured water formation. Solving this problem depends on the following:hole preparation before running the casing and cementing the annulusproper slurry weight to help control formation influx and help prevent formation fracture

In late 1999, British Petroleum (BP) experienced a well failure in the Marlin development in deepwater Gulf of Mexico (GOM). Within hours of starting production, the production tieback casing collapsed, causing failure of the production tubing. Pressurization of outer annuli due to production thermal effects was identified as one of two possible root causes of the failure. The oil and gas industry has been observing, documenting, and reporting cases of annular pressure buildup (APB) in annuli for several years.1 On land, platform, and spar-type wells having access to annuli, the problem can usually be dealt with by bleeding off the annular pressure as needed. Subsea completions, however, do not allow this capability, and the technology to provide access is still being studied. Especially susceptible to APB are deepwater developments in which the differential between mudline temperatures and flowing-production temperatures can exceed 125° to 200°F. A key technique developed during the Marlin project to help prevent APB was the use of nitrified cementing spacers. These spacers provide a compressible cushion that can absorb the pressurization effects caused by thermal heating in the annulus. In addition to carrying nitrogen, the spacers can also provide adequate mud removal and remain stable for at least 72 hr. These features help prevent the migration of nitrogen into the riser prior to setting the wellhead seals. Based on a series of pressure/volume/temperature (PVT) tests and well design simulations, the minimum foam quality of nitrogen was determined. Service company and operator engineering staffs worked proactively and integrated their efforts to identify, evaluate, plan, and implement multiple options for resolving this substantial well-integrity issue. This paper reviews the problems associated with APB, details the large-scale testing that was conducted, and the resulting best practices that help prevent APB from affecting the casing design. These best practices were successfully implemented on the Marlin subsea development, and other projects are also using these techniques. Introduction Marlin History, A-2 Well Failure Summary An incident investigation team was formed to evaluate the failure of Well A-2. The team provided detailed analyses of probable failure modes and determined that there were two possible root causes of the failure:excessive annular pressure buildup, orannular hydrate disassociation. The failure analysis results were applied to the five remaining Marlin wells.2 When these original Marlin wells were batch drilled, a number of mitigation techniques presented in this paper were not implemented and were no longer available for consideration. As a result, the redesign of the Marlin completions had to focus on VIT (Vacuum Insulated Tubing) and fiber optic monitoring systems as a means of both controlling and observing thermal behavior.3 Early in the failure investigation of Marlin Well A2, a root cause analysis was performed to discern the most likely causes of tubing ovalization.4 The possible causes included the following:Excessive helical (column) buckling of the production tubingHydrate formation and dissolutionTrapped annulus pressure leading to casing collapseMiscellaneous issues such as proper tubulars and wellhead movement Marlin History, A-2 Well Failure Summary An incident investigation team was formed to evaluate the failure of Well A-2. The team provided detailed analyses of probable failure modes and determined that there were two possible root causes of the failure:excessive annular pressure buildup, orannular hydrate disassociation. The failure analysis results were applied to the five remaining Marlin wells.2 When these original Marlin wells were batch drilled, a number of mitigation techniques presented in this paper were not implemented and were no longer available for consideration. As a result, the redesign of the Marlin completions had to focus on VIT (Vacuum Insulated Tubing) and fiber optic monitoring systems as a means of both controlling and observing thermal behavior.3 Early in the failure investigation of Marlin Well A2, a root cause analysis was performed to discern the most likely causes of tubing ovalization.4 The possible causes included the following:Excessive helical (column) buckling of the production tubingHydrate formation and dissolutionTrapped annulus pressure leading to casing collapseMiscellaneous issues such as proper tubulars and wellhead movement

In late 1999, BP plc experienced a well failure in the Marlin development in deepwater Gulf of Mexico. Within hours of starting production, the production tieback casing collapsed, causing failure of the production tubing. Pressurization of outer annuli because of production thermal effects was identified as the most likely cause of the failure. IntroductionThe industry has reported cases of annular pressure buildup (APB) in annuli for several years. 1 In land, platform, and spar-type wells with access to annuli, APB is usually handled by bleeding off annular pressure as needed. Subsea completions, however, do not allow this capability, and the technology to provide access is still being studied. Especially susceptible to APB are deepwater developments in which the differential between mudline and flowingproduction temperatures can exceed 125°to 200°F.Three primary mitigation techniques were employed to help reduce the impact of APB on the Marlin project. The first used an enhanced casing design capable of withstanding higher pressure conditions. In the second method, a burst disk was installed in the outer casings to provide a controlled leak path. The third technique involved the application of nitrified cementing spacers in the annulus to provide a compressible cushion and to help reduce the effects of temperature expansion.Service company and operator engineering staffs worked proactively and integrated their efforts to identify, evaluate, plan, and implement multiple options for resolving this substantial wellintegrity issue. This article reviews the problems associated with APB, describes the large-scale testing conducted in the Marlin project, and discusses the best practices developed to help prevent APB from affecting casing design. These best practices were successfully implemented on the Marlin subsea development, and other projects are also using these techniques.