TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractVerifying pressure integrity of a casing string and the adjacent formation is an important requirement during drilling of a well. Crucial decisions on mud weight, kick tolerance, and the setting depth of the next casing string are based on the outcome of formation strength tests (FST) such as leak-off tests (LOT) or formation integrity tests (FIT). Moreover, government regulations usually require that a minimum integrity is guaranteed before a well may be deepened.Yet the majority of FSTs and their interpretation currently carried out in the field can only be characterized as inadequate. Commonly, FSTs lack quality and accuracy due to (in)sensitivity in the hydraulic system to subtle pressure effects in the wellbore, use of highly compressible synthetic or oil muds, non-linear thermal profiles, poorly-understood formation stress and strength behavior, or simply by poor data capturing (e.g. by hand-generated plots). This may have a significant negative impact on the drilling operation. For instance, when mud weight windows are incorrectly assessed after testing, lost circulation or well control problems may ensue on wells with tight drilling margins.Here, we highlight several of the problems underlying current FSTs and their interpretation, illustrating them with actual field examples (such as the discrepancy often observed between surface readings and downhole pressure-while drilling (PWD) readings obtained while testing), and show how test artifacts can be either avoided or accounted for. A case is made for the use of downhole recorded pressure data to correctly determine casing shoe strength.

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

The use of lightweight cements for oilfield applications has progressed from conventional systems used in the past to some very specialized blends used currently. Conventional water-extended cement slurries and their minimum densities of 11.5–12 lb/gal were all that were available until the late 70s when hollow spheres and foam cementing were first introduced. Technology for both foamed and microsphere slurries has evolved considerably over the last 10 years. The conventional water-extended cement slurries were considered adequate for offshore wells until the late 80s when shallow drilling hazards found in deepwater, necessitated higher performance lightweight cements. The first specialty cements that showed success used blends of microfine cement and microspheres while the next generation of specialty cements used nitrogen and a special blend of base cement to produce high-performance foamed cements that were very successful. Advanced liquid additives then developed allowed the same high-performance results without the requirement of storing specially blended cements offshore. Recently the introduction of new, high-strength beads has provided the advantages presented with beaded slurries under the higher operating pressures currently encountered in deep water. However, special blending, transportation, and mixing issues are still significant. These newer bead technologies have also enabled effective slurry design at lower and lower densities. In addition to the usual blending and transportation issues these new ultra-light designs present additional slurry mixing issues because maintaining a constant density no longer ensures a correct cement to water ratio. In this paper a new technology for bead delivery is presented to illustrate how the industry can gain all of the advantages normally presented by these beaded slurries while avoiding the blending, transport, and mixing issues. Discussion is included to describe the potential of this new technology to help reduce cost associated with offshore cementing operations. By eliminating the need for blended cement, the rig can minimize the logistical concerns, reduce waste of excess specialty blends, avoid the need of separate silos for specialty blends, and provide the capability of changing slurry density at the time of delivery. This paper presents (1) the history and evolution from the first use of lightweight additives through this newly patent-pending technology, and (2) the methodology and guidelines for use of each technology with other lightweight technologies available. Background General Normally cement is mixed at a density of 15.6 – 16.4 lb/gal depending upon the type of cement used. When conditions are encountered that call for heavier slurry properties, water may be decreased and/or weighting material added to increase the cement density, in an attempt to keep the reservoir fluids from entering the annulus. When cementing past zones with a low fracture gradient the cement density is reduced to prevent losses of bulk cement fluid into the formation. Current slurry design technology allows for this density reduction to be accomplished through any one of three different mechanisms, discussed in the following sections.1–3 Water Extended The addition of any amount of water to a cement slurry will reduce that slurry's density and can cause slurry-stability problems. To allow the addition of enough extra water to significantly reduce the slurry density while maintaining slurry stability, additional additives are added in conjunction with the extra water. Typical examples of these water-extending additives are: bentonite, sodium or potassium silicates, fumed silica, diatomaceous earth, and pozzolan. Often these materials are mistakenly referred to as lightweight additives, but in reality they are water-extending additives. Commonly these water extending additives are inexpensive. When combined with the large increases in slurry yield attainable from the additional water, this class of cement slurries will normally be the cheapest available. While inexpensive, these slurries will also have the lowest level of performance of all cementing systems.

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.

Summary Verifying pressure integrity of a casing string and the adjacent formation is an important requirement during drilling of a well. Crucial decisions on mud weight, kick tolerance, and the setting depth of the next casing string are based on the outcome of formation-strength tests (FSTs) such as leakoff tests (LOTs) or formation-integrity tests (FITs). Moreover, government regulations usually require that a minimum integrity is guaranteed before a well may be deepened. Yet the majority of FSTs and their interpretations currently carried out in the field can only be characterized as inadequate. Commonly, FSTs lack quality and accuracy because of insensitivity in the hydraulic system to subtle pressure effects in the wellbore, use of highly compressible synthetic or oil muds, nonlinear thermal profiles, poorly understood formation-stress and -strength behavior, or simply because of poor data capturing (e.g., by using hand-generated plots). This may have a significant negative impact on the drilling operation. For instance, when mud-weight windows are assessed incorrectly after testing, lost circulation or well-control problems may ensue on wells with tight drilling margins. Here, we highlight several of the problems underlying current FSTs and their interpretations, illustrating them with actual field examples [such as the discrepancy often observed between surface readings and downhole pressure-while-drilling (PWD) readings obtained while testing], and show how test artifacts can be either avoided or accounted for. A case is made for the use of downhole recorded pressure data to determine casing-shoe strength correctly. Introduction FSTs are carried out during the drilling phase of a well after a string of casing has been cemented and before a new section of hole is drilled. In these tests, the cement at the casing shoe is drilled out and a section of new hole (typically 10-20 ft) is drilled, the blowout preventer (BOP) is closed around the drillpipe (DP), and the well is pressured up slowly using mud. Testing serves the following purposes:To confirm the strength of the cement bond around the casing shoe and to ensure that there is no open flow path to formations above the casing shoe or to the previous annulus. If such a flow path exists, remediation of the casing shoe (e.g., by cement squeeze) is necessary.To investigate the capability of the wellbore to withstand additional pressure (as dictated by the in-situ stresses and formation strength) below the shoe in order to assess the competence of the well to handle an influx of formation liquid or gas and to allow for proper well design with regard to the safe drilling depth of the next hole section.To collect data on formation strength and in-situ stresses that can be used for wellbore-stability and lost-circulation prediction purposes, both for the well being drilled currently and for future well designs (e.g., in a multiwell development). Proper planning, selection of a fit-for-purpose test method, and execution, interpretation, and reporting of FST results are essential for such important matters as picking appropriate casing points, maintaining zonal isolation, establishing maximum allowable annular surface pressures (MAASPs) and kick tolerances, maintaining well control, determining conditions for cuttings reinjection (CRI), avoiding wellbore instability, and preventing exorbitant mud losses. Specific regulations govern FSTs and associated follow-up on FST outcomes in many parts of the world. Many well engineers and field staff regard FSTs as well-established and routine, with straightforward execution and interpretation. In our experience, however, FSTs present many complications that are rarely accounted for in actual field practice. Some of these complications are new and associated with the introduction of new systems or practices [e.g., the widespread use of synthetic-based muds (SBMs) in deepwater wells, with associated mud-compressibility, thermal-expansion and gel -trength issues]. Others have probably always been a part of FSTs but have not been accounted for properly, such as the effects of temperature on fracture gradient and the location of the cementing unit on pressure analysis. We discuss several of these complications here and highlight ways to account for them or avoid them altogether. Our aim here is to minimize the downside risks associated with faulty FST execution or interpretation, which may give rise to serious operational problems.