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Accurate temperature modeling on an offshore deepwater well or potentially any other type of well can result in reduced, non-productive time (NPT) attributed to waiting on cement (WOC) time. Understanding the downhole temperature behavior and heat recovery during the static time after placement of cement slurry can provide an opportunity to minimize WOC-time for compressive-strength development. Drilling engineers encounter a variety of requirements by regulatory agencies across the globe concerning cementing operations. Although the regulatory-agency guidelines and expectations in many cases are detailed and challenging, the operational requirement and cost-saving prospects by operators go beyond some of these recommended/required expectations. Almost any optimization that can expedite commencement of the drilling operation after a cement job (for example, drilling, completing, moving rig) should improve the cost-effectiveness of the drilling program. Water temperature gradient profiles from sea surface to seabed through shallow formations below the seabed exhibit diverse characteristics in different fields. An accurate bottomhole static temperature (BHST), or the undisturbed bottomhole temperature (BHT) and understanding the bottomhole circulating temperature (BHCT) behavior is a crucial factor to success of deepwater field developments. This paper will discuss how best practices in combination with optimized downhole temperature modeling can potentially reduce the number of hours in WOC-time without introducing any additional risk factors into the cementing/drilling operations. Calculating accurate downhole temperature and pressure profiles, which are also used for pipe-body movement and casing-and tubing-load analysis, assists cementing, drilling, and completion engineers to produce highly effective solutions. Introduction As the oil and gas industry witnesses less conventionally accessible hydrocarbon reservoirs, the focus shifts more towards large reservoirs in more challenging environments. These resources have become more technically and economically accessible as new technologies emerge to make more effective exploration possible. One of the most promising areas of discovery is the deep/ultra deepwater offshore reservoirs. In many cases, deepwater reservoirs, such as the North Sea have shown more productivity and relatively lower life compared to average deep wells on land. Many wells have also been drilled in shallower waters where drilling operations are commonly less complex to conduct. Deep and ultra deepwater reservoirs have historically been less explored (compared to shallow-water fields) in spite of their great potential because of the complexity and availability of the required technologies, including cementing. Today's cementing technologies allow the engineers to plan ahead and design sealant systems that will endure or exceed all the operational cyclical conditions. Zonal isolation effectiveness and casing protection are two of the critical factors in every well's life that will help ensure production continuity and minimal to zero remedial costs. Some deepwater wells in the GOM are known to produce more than 13,000 BOPD (barrels of oil per day). In the Middle East, many wells produce in excess of 15,000 to 20,000 BOPD. It is more beneficial to seek and explore some of the deeperwater opportunities, as these reservoirs can be very rewarding if wells are drilled and completed successfully. Additionally, a general industry rule for offshore-well classification in regards to water depths is to define shallow as depths of less than 1,500 ft (457 m) of water, deep as 1,500–4,000 ft (457–1219 m) of water, and ultra-deepwater as 4,000 ft (1219 m) of water and greater. Recently, some operators have been calling anything that exceeds the 5,000 ft (1524 m) of water depth "deep water" because drilling in 1,500 ft (457 m) of water has become rudimentary as a result of achieved technological advancement and experience.
Accurate temperature modeling on an offshore deepwater well or potentially any other type of well can result in reduced, non-productive time (NPT) attributed to waiting on cement (WOC) time. Understanding the downhole temperature behavior and heat recovery during the static time after placement of cement slurry can provide an opportunity to minimize WOC-time for compressive-strength development. Drilling engineers encounter a variety of requirements by regulatory agencies across the globe concerning cementing operations. Although the regulatory-agency guidelines and expectations in many cases are detailed and challenging, the operational requirement and cost-saving prospects by operators go beyond some of these recommended/required expectations. Almost any optimization that can expedite commencement of the drilling operation after a cement job (for example, drilling, completing, moving rig) should improve the cost-effectiveness of the drilling program. Water temperature gradient profiles from sea surface to seabed through shallow formations below the seabed exhibit diverse characteristics in different fields. An accurate bottomhole static temperature (BHST), or the undisturbed bottomhole temperature (BHT) and understanding the bottomhole circulating temperature (BHCT) behavior is a crucial factor to success of deepwater field developments. This paper will discuss how best practices in combination with optimized downhole temperature modeling can potentially reduce the number of hours in WOC-time without introducing any additional risk factors into the cementing/drilling operations. Calculating accurate downhole temperature and pressure profiles, which are also used for pipe-body movement and casing-and tubing-load analysis, assists cementing, drilling, and completion engineers to produce highly effective solutions. Introduction As the oil and gas industry witnesses less conventionally accessible hydrocarbon reservoirs, the focus shifts more towards large reservoirs in more challenging environments. These resources have become more technically and economically accessible as new technologies emerge to make more effective exploration possible. One of the most promising areas of discovery is the deep/ultra deepwater offshore reservoirs. In many cases, deepwater reservoirs, such as the North Sea have shown more productivity and relatively lower life compared to average deep wells on land. Many wells have also been drilled in shallower waters where drilling operations are commonly less complex to conduct. Deep and ultra deepwater reservoirs have historically been less explored (compared to shallow-water fields) in spite of their great potential because of the complexity and availability of the required technologies, including cementing. Today's cementing technologies allow the engineers to plan ahead and design sealant systems that will endure or exceed all the operational cyclical conditions. Zonal isolation effectiveness and casing protection are two of the critical factors in every well's life that will help ensure production continuity and minimal to zero remedial costs. Some deepwater wells in the GOM are known to produce more than 13,000 BOPD (barrels of oil per day). In the Middle East, many wells produce in excess of 15,000 to 20,000 BOPD. It is more beneficial to seek and explore some of the deeperwater opportunities, as these reservoirs can be very rewarding if wells are drilled and completed successfully. Additionally, a general industry rule for offshore-well classification in regards to water depths is to define shallow as depths of less than 1,500 ft (457 m) of water, deep as 1,500–4,000 ft (457–1219 m) of water, and ultra-deepwater as 4,000 ft (1219 m) of water and greater. Recently, some operators have been calling anything that exceeds the 5,000 ft (1524 m) of water depth "deep water" because drilling in 1,500 ft (457 m) of water has become rudimentary as a result of achieved technological advancement and experience.
Drilling operations are presented with challenges for both normal and complex wellbore environments with a focus on minimizing nonproductive time while successfully achieving the well objectives. In some cases, it is likely to reach the well objectives and remedial cementing may play a significant part whether it is due to exploration or wildcat-type wells, complex well construction, or the geological uncertainties. As a necessary evil, being able to plan for contingencies and success when faced with remedial cementing applications can reduce the potential replication of treatments and improve the extent of nonproductive time. When these situations arise during deepwater operations, there are challenges beyond the traditional cementing scope of work such as multiple temperature and pressure gradients, subsea equipment, and large-bore tubulars. Drilling deeper these factors may also include lithology, wellhead clearances, stuck pipe, failure of barriers, and/or an unstable well. Furthermore, traditional service tools find limited success with remedial operations in large-bore casing/tubulars, often requiring alternative solutions, including pumping through bottom hole assemblies, using inflatable packers, and developing other non-traditional placement techniques. This paper will present methods to improve the success of cement placement while performing remedial cementing operations in an effort to reduce nonproductive time and execute common contingency planning. In addition, specific well situations and events executing these methods will demonstrate the impacts to remediate the necessary evil.
A multitude of challenges exist when cementing production liners for deepwater operations. In many platform operations, cutting windows to sidetrack and drill highly deviated well paths to intersect reservoir targets result in difficulty obtaining adequate casing standoff due to tight inside diameter (ID) restrictions from previous casing architecture. Many of the zones near the target interval may have significant pressure depletion which can lead to expensive Synthetic Based Mud (SBM) losses and associated non-productive time (NPT). The size of the production liner is dependent on the wellbore architecture and completion plan. Thus in most cases, the borehole must be under-reamed in order to provide for adequate cement sheath thickness. In these cases, centralizer selection and placement can be challenging or all together impractical. Cementing in SBM environments has also been traditionally more challenging because special considerations for spacer/surfactant/mud design and testing are required to effectively displace the mud and "water-wet" the formation/casing for good quality cement-bonding. Technology improvements in spacer and surfactant package formulations provide a more qualitative method for optimum surfactant design to maximize mud removal and provide a bonding surface to the formation. Liner hanger selection may not always provide the capability for pipe rotation which has shown to be very effective for mud removal and increased circumferential cement coverage. Without pipe rotation, additional key techniques for successful cementation must be prioritized. A process driven decision matrix is presented along with a recent selection of successful production liners to support the design concept.
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