The May field in Offshore Mexico is difficult to drill due to the presence of boulders and conglomerates within the top hole section. The interval is traditionally drilled with a conventional 18 1/2" bit and BHA. However, an enlarged hole is planned as contingency to provide an improved cement bond with the casing utilized. Due to casing drift, this requires the use of hole opening string tools to provide a final hole diameter of 21".Prior hole opening runs have endured significant vibration and resultant mechanical damage to the tools and pilot bits. An offset well utilized commercial concentric hole opening tools that have cutter blocks that can be activated and retracted so that it can be pulled back through the casing. The hole opening section required a total of eight string reamer tools and three 18 1/2" pilot bits to reach TD.A unique eccentric string reamer tool was selected that utilizes a mid-reamer section for improved string stabilization and hole enlargement. This was coupled with an eccentric vibration dampening tool, specifically positioned in the string to disturb damaging vibration harmonics. In order to refine parameter recommendations, Finite Element Analysis Software was utilized to model the harmonic behavior of the drill string. This assembly, combined with a point-the-bit rotary steerable tool drilled this challenging hole section in 9 days, delivering low vibrations and gauge hole. An estimated $4.4 M was saved compared to the original well plan and $11.5 million compared to the direct offset well for this interval.

Temperature is a parameter of great importance when simulating and modeling cementing or temperature-activated fluids (McSpadden and Glover 2008) because it affects the amount of retarders or accelerators needed to avoid undesired phenomena, such as premature cement setting or incomplete consolidation of the treatments. In 1964, API introduced the first set of tables (API 2005) that listed the circulating temperatures and hydrostatic pressures for certain wellbore circumstances and bottomhole conditions and the fluids that could be used in different well treatments, such as cementing, lost-circulation control, and water or gas control, etc. The API procedures have been widely adopted and recognized in the oil industry, and most operating companies feel comfortable using them. However, increased demand for oil and gas has forced operators to perform drilling, completion, and maintenance operations in deeper and more complicated zones. These zones are often classified as high-pressure/high-temperature (HPHT) fields. Currently, combining computational tools, such as computer simulation software and measurement sensors, allows operators to accurately measure temperature and pressure values and adjust them with well-known heat-transfer models; as a result, possible temperature changes during complex operations can be more accurately modeled. This paper presents multiple case histories showing the significance of using bottomhole pressure/temperature (P/T) measurement tools and the modified modeling of the heat-transfer effects as a function of operational parameters (flow rate, density, wellbore geometry). With more accurate temperature data, laboratory testing can be performed to better predict the behavior of the treatments mentioned when exposed to the more complex bottomhole conditions encountered.

Land and offshore drilling operations along the Tabasco coastline of the Gulf of Mexico notoriously present difficulties posed by the variations in pore pressure, depleted reservoirs, and, in the majority of cases, highly fractured carbonates--the last a cause of negative windows between pore pressure and fracture pressure and, thus, whole sections with complete circulation loss. It is not surprising that the drilling of these deposits takes much more time than planned. Nonproductive-time (NPT) events are particularly associated with lost circulation and/or gas influxes in high-pressure formations, well-control processes, stuck-pipe problems, deviated wells, and in some cases, wells being abandoned without the objectives having been met. To mitigate these problems, managed pressure drilling (MPD) technology, using an automated system, was implemented. The objective was to determine the limits of the operating window and to perform an equivalent circulating density (ECD) control to find a balance between the losses and gains, reducing the losses as much as possible and minimizing volume of influx from high-pressure gas intervals. This paper describes the objectives, planning, technology used, problems encountered, and lessons learned during the first application of MPD technology using an automated system in an offshore well in the Gulf of Mexico, along the Tabasco coastline.

Pemex, the local oil producer in Mexico, has identified young fields as potential alternatives to compensate for the production decline experienced in recent years. However, those with the largest reserves and the lightest oil offer the most difficult drilling conditions. Just such an example is a target field in the Marine Southwest region where production objectives have been compromised by significant delays in drilling operation. The complexity of the 17 ½-in borehole section, made so by high lateral and torsional bottomhole assembly (BHA) vibration, resulted in costly drilling incidents, such as, drillstring twist off, physical damages, and failures of downhole tools. These incidents resulted in fishing and side track operations that averaged 15 days of nonproductive time per 17 ½-in section per well. This paper will explain how rotary steerable BHA designs developed out of a need to achieve drilling stability and ultimately resulted in an enhancement on average ROP. This discovery, termed Powered Rotary Steerable System (RSS), combines, within the same BHA, a mud motor power section with a push-the-bit RSS tool. This system decouples surface RPM from downhole RPM allowing for the low revolution rotation of the drill string, thus preventing vibration but not sacrificing the rotation and hydraulic power needed by the bit to generate good rate of penetration (ROP). The design was capable of drilling the 17 ½-in section of the field in one run and reduced drilling time from 36 days to 8 days; nonproductive time due to BHA vibration was completely eliminated in additional wells.

The Xanab field is located off the coast of Tabasco state in the southeastern Gulf of Mexico. In this field, oil reserves accumulate in dolomitized carbonate rocks at the Upper Jurassic Kimmeridgian formations. While drilling the Xanab 11 well, a narrow margin of 0.2 g/cm3 was expected between the reservoir and fracture pressures, based on correlative well data. Given this condition, conventional drilling methods could cause severe kicks and drilling fluid losses. A managed pressure drilling technique (MPD) makes it possible to exert and maintain a constant bottomhole pressure (BHP) by applying a backpressure in the annular space to accurately choke the fluid flow returning from the well with a closed and pressurized surface-control system. In the event that a kick is detected, the BHP can be quickly increased by applying a backpressure with the choke at the wellhead to immediately control the kick. Similarly, if fluid losses are encountered, the downhole pressure can be quickly reduced by decreasing the backpressure, thus adapting to the requirements of the well. This paper describes the application of the MPD technique during the 5-7/8 in. hole section of the Xanab 11 well. The MPD technique made it possible to work within a narrow operational window and to identify formation tops through drill breaks, which are usually followed by severe fluid losses and kicks. Abnormal pressures were detected earlier, and surface conditions were adjusted to prevent well influx scenarios that could result in severe kicks or blowouts. Consequently, only two kicks occurred. In addition, fluid losses were identified earlier, which enabled preventive measures to be applied rapidly to avoid sticking. The MPD technique enabled a reduction of 44% in drilling scheduled times; it also resulted in a decrease in the volume of fluid lost to the formation and in non-productive time (NPT), as compared to conventionally drilled correlative wells. In addition, the amount of time required for production well clean up was only six hours, which helped joining the reserves to production faster. The use of a closed system prevented gasification events at the drill floor, mud shakers, and pits, thereby creating safer working conditions for the personnel involved. Technical adjustments were made to fit the onshore MPD equipment to the limited space available in the offshore work environment. Introduction The Xanab field is located off the coast of Tabasco in the southeastern Gulf of Mexico (Fig. 1a). Its structure is presented as an elongated anticline, bounded by two faults (Drilling Program for Offshore Development, Well Xanab 11). From logs run on the Xanab 101, 1DL, 1, and 31 wells, a pressure ramp occurs at approximately 4900 m at the entrance to the Lower Miocene zone, which resulted in a narrow operational window. Fig. 1b shows the 3D view of the trajectory of the Xanab 1 DL, Xanab 31, and Xanab 11 wells. A review of the drilling records and events logs of the correlative Xanab 1DL and Xanab 31 wells in the 5-7/8 in. hole section was performed to understand the well trajectory plans, well geometry, average mud weights, kick frequency, severity of the influxes, events from the well, maximum annular pressure increase as a result of an influx, number of well control events, total number of drilling days, and average rate of penetration per day per section to drill. This data was then placed in individual charts for each well to show the depth vs. the number of days and annular pressure.