This paper was prepared for presentation at the 1999 SPE/IADC Drilling Conference held in Amsterdam, Holland, 9-11 March 1999.
fax 01-972-952-9435. AbstractIn 2002 the Hibernia Management and Development Company (HMDC), led by ExxonMobil Canada, embarked upon the development of the northern most compartment of the Hibernia development project, ('A' Block). To access these reserves, it was proposed to drill and complete a 31,000 ft measured depth (MD) oil producer with a horizontal departure and vertical depth that would exceed the present day industry extended reach drilling (ERD) envelope.Successfully drilling this world-class well would require the application and extension of currently available drilling and completion technology. Meeting the project goals would demand the installation of a large monobore completion system with offshore-Canada's deepest downhole telemetry system. The proposed trajectory would require management of weak and unstable intervals across an extended 17,000 ft MD intermediate section. This trajectory would necessitate the installation of record length production casing strings under high friction load. Subsurface tool reliability under extreme cyclic loading would be needed, especially at the lower wellbore sections where downhole tool failures would be costly due to depth and trip time. The project would require the development of effective strategies to mitigate very high circulating pressures and fluid rheology at extended distances. Drill pipe and tool joints would require upgrade to meet the higher anticipated loads for this program. Completion equipment would also require significant enhancements to meet the pressure and axial load requirements of the wellbore. Planned intervention tools would require modification to allow passage through the extended reach sail angle. Wellbore tractors would be refitted and shop testing would be conducted to ensure all tools were ready for application.To meet these challenges HMDC would leverage existing local experiences 1 while at the same time engage recognized international expertise to supplement existing practices. Technical work sessions were conducted during the planning phase to start the communication process to all stakeholders (including service providers) and to identify critical technical boundaries and key technologies to extend the current ERD envelope. The comprehensive review and upgrade of Hibernia ERD practices was effected through external engagement of ERD experts for worldwide lessons learned.Internal resources were accessed to effectively integrate the latest concepts in hole cleaning and wellbore stability. All the while, operational and design revisions were based upon, and complemented by, successful existing Hibernia ERD practices.
Summary Shallow water flows (SWF) from overpressured aquifers have been a persistent problem in the deepwater Gulf of Mexico (GOM) and can create significant financial and operational risks for exploration and development drilling programs. For the GOM, SWF intervals typically occur between 300 and 2,500 ft below mudline (BML) and in water depths greater than 1,500 ft. If left unchecked, the disturbance from the water flow can cause loss of soil strength surrounding the wellbore, thereby compromising the structural integrity of the well. In industry, extreme cases have led to collapsed casing and/or total loss of wellbores. This paper details the up-front planning efforts implemented and the operational procedures utilized to successfully mitigate a SWF event experienced at the Titan No. 1 exploration well drilled in Garden Banks Block 785 (GOM), in 4,640 ft of water. Operations at Titan were based on the philosophy that performing a shallow hazards assessment, preparing and implementing SWF contingency plans, drilling a 9 7/8-in. pilot hole (for dynamic kill), identifying a SWF zone quickly, controlling a water-flow zone with weighted mud (while drilling riserless), and using nitrified foam cement to seal off a water flow behind 20-in. conductor pipe, were all critical in successfully containing and drilling through a SWF occurrence. Introduction Although it is generally believed that overpressured shallow sands are the result of rapid sedimentation, they can also be caused by other mechanisms including sand collapse, gas charging, and salt tectonics. SWF incidents are Gulf-wide and have been experienced most notably in areas such as Garden Banks, Green Canyon, Mississippi Canyon, and Viosca Knoll (Fig. 1). SWF sands are most troublesome in the 24- or 26-in. conductor hole section of the wellbore since this section is usually drilled with seawater (while taking returns on the seafloor) and prior to the installation of the subsea blowout prevention (BOP) stack and marine riser. Once penetrated, the overpressured sand causes an influx of water, sand and/or sediment into the wellbore. If left uncontrolled, this flow can lead to large washouts resulting in inadequate zonal isolation when cementing 20-in. conductor casing. Additionally, an uncontrolled flow of water, sand, and/or sediment has the ability to remove the vertical support surrounding the wellbore, thereby allowing the conductor casing to buckle and, if there is a localized group of wells present, could allow crossflow between wells behind pipe. In other cases, a SWF may channel up behind casing becoming evident only later in the drilling operation. This scenario may also lead to the loss of the well. Risk Mitigation for Shallow Water Flow In general, there are six main methods currently being used by operators to mitigate the effects of SWF, and operators may use one or a combination of these methods. The first option is implementing a drilling plan that controls the SWF with weighted mud. The philosophy behind this scenario is to quickly identify the SWF and to immediately stop the flow with weighted mud. Drilling of the conductor hole interval may then be resumed with sufficiently weighted mud to keep the SWF contained while taking returns to the seafloor (since the subsea BOP stack and marine riser are not yet run). To identify the flow, frequent flow checks through observation by the remotely operated vehicle (ROV) are used along with constant monitoring of downhole conditions via logging-while-drilling (LWD) and annulus pressure-while-drilling (PWD) tools. Once encountered, the flow is killed with weighted mud and weighted mud is then used for all subsequent drilling of the section. This method requires the maintenance of an adequate supply of weighted mud should it become necessary to kill and drill beyond a shallow pressured sand. The major advantages to this first option are that it provides the opportunity to successfully drill through even the shallowest SWF zones to the planned 20-in. conductor casing point, and it affords an excellent chance to minimize hole washouts (which is critical when attempting to obtain zonal isolation of the SWF when cementing). This method was used at Titan and will be discussed in greater detail in the remainder of this paper. Another option may be to top set 20-in. conductor casing above the suspected SWF zone (provided the casing setting depth is sufficient to ensure adequate formation strength at the casing shoe to allow mud returns back to the rig). This scenario allows the operator to install the subsea BOP stack and marine riser and begin circulating mud returns to surface when drilling the subsequent hole section. Although this method has the advantage of conserving the weighted mud, this method depends on the depth of the shallow sand and may require at least one additional casing string if the flow zone is very shallow. Additionally, the weak formation integrity, typical in the shallow sections of the Gulf of Mexico (GOM), may lead to lost returns. The third method is to drill a larger 30-in. hole from below 36-in. structural casing and set 26-in. pipe across the shallow flow zone where formation integrity is still too weak to run the subsea BOP stack and marine riser. While this method may seal off the very shallow flow zones, well planning must include the installation of a hanger inside the 36-in. structural casing to allow the hang off of the 26-in. pipe. Also, additional time will be spent running and cementing the additional string of pipe and drilling out the cement from within the 26-in. casing. Further, the SWF may have washed out the hole to such an extent that it could lead to zonal isolation problems when cementing the 20-in. casing. The fourth option is to drill riserless with seawater allowing the overpressured sand to flow until reaching conductor casing depth. The well is then killed with weighted mud, and the 20-in. conductor casing is run and cemented. This technique allows the operator to quickly put any SWF zones behind pipe, but it may also allow the hole to become enlarged (once again leading to zonal isolation problems during cementing operations). The fifth and sixth methods are drilling the shallow hole section from start to finish with weighted mud, and drilling the shallow hole section with a top-set 26-in. riser. Although the fifth method may prevent a SWF from occurring, it requires the up-front commitment to use and discharge weighted mud even if a shallow flow zone is not present. As for the sixth method, an additional casing string is required (to top set the potential water flow zone). This method also necessitates the up-front purchase of the 26-in. riser, further adding to cost. In this scenario, weak formation integrity, typical in the shallow sections of the GOM, could also lead to lost returns.
Since 1996, ExxonMobil has conducted an extensive deepwater exploration / appraisal program in West Africa. In an effort to achieve improvement in production testing performance, ExxonMobil's West Africa Deepwater Drill Team pursued key initiatives to deliver quality well test operational results. These initiatives included performing effective long-term and near-term planning, highgrading equipment quality control and inspection practices, making appropriate use of selective new technology, enhancing standardized procedures by capturing lessons learned and best practices, performing rig-site engineering supervision of production testing operations, and communicating captured follow-up recommendations to service contractors. To execute these continuous improvement initiatives, a single dedicated test engineer was assigned to plan and oversee all West Africa well testing operations. As a result of this increased focus, the average non-productive time (NPT) per test has been reduced from approximately 30% to 6% and the overall test time has been reduced by about 40%. The methods and resources used to achieve these improvements are discussed in detail in this paper. Overview of Well Test Performance and Strategy ExxonMobil is a leading holder of deepwater acreage in West Africa, with interests in 17 blocks totaling nearly 16 million acres in the countries of Angola, Nigeria, Equatorial Guinea, and Republic of Congo (Figure 1). Since 1996, ExxonMobil as operator has drilled 37 exploration / appraisal deepwater wells resulting in the discovery of significant hydrocarbon reserves. These wells were drilled with both moored and dynamically positioned drillships and semisubmersible rigs in water depths ranging from 2000–6000 ft (600–1800 m). By mid-2002, this has resulted in ExxonMobil conducting more than 20 deepwater production tests offshore West Africa. Deepwater tests in West Africa require significant planning due to the region's remoteness and limited contractor and equipment availability. The use of specialized deepwater test equipment results in daily spread-rates during testing operations that can exceed $450K per day. Additionally, because of the exploratory nature of the drilling activity in this region, production test timing and well characteristics are unpredictable. As such, one of the most challenging aspects of testing West Africa deepwater wells has been to maintain testing operations flexible enough to accommodate a wide range of production conditions on very short notice. Early Test Performance Prior to the year 2000 and before the assignment of a dedicated test engineer, ExxonMobil well testing performance for offshore West Africa was on par with industry. The typical completion and test phase required around 13 days with NPT averaging approximately 30% (excluding flow periods) (Figure 2). Goals and Initiatives However, the numerous well tests conducted by ExxonMobil offered an opportunity to evaluate and strive to improve testing performance. As a result, in late 1999 / early 2000, West Africa Exploration Deepwater Drill Team Management established two key goals:Reduce NPT associated with completion and test phase operations from approximately 30% to around 5%.Improve testing operational efficiency through the implementation of best practices and lessons learned. To achieve these goals, the Drill Team assigned a drilling engineer from within the team to focus specifically on well test operations. The test engineer's responsibilities were to include oversight of all West African testing operations and implement specific initiatives aimed at achieving the two key goals. Post-Initiative Results As a result of the methods described in this paper, the typical completion and test phase was reduced to around 8 days with NPT averaging approximately 6% (excluding flow periods) (Figure 3). This equated to nearly $20M of cost savings in well tests performed from 2000 through mid-2002 and validated the benefit of assigning a dedicated test engineer to testing operations.
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