The Red Oak Field is located in the Arkoma Basin in Southeastern Oklahoma. The Field recently exceeded peak production levels in what was previously deemed a fully developed reservoir, through an ongoing successful infill drilling program based on the use of three-dimensional (3-D) seismic. Moreover, the redevelopment program has surpassed the 100 well mark and has delivered some high rate gas wells. The field may be characterized by its dry gas and multiple pay horizons in what has long been known to be "crooked-hole country". In situ compressive strengths range from 10,000-psia through the Pennsylvanian to 55,000-psia through the Ordovician. Much work has been done in the past to optimize air drilling operations for shallow wells; however, as deeper horizons are exploited new technologies have been implemented in order to deliver continuous improvement. Drilling improvements in recent years have included the introduction of a state-of-the-art drilling rig, further optimization of air drilling operations and the introduction of Polycrystalline Diamond Compact (PDC) bits. A down-hole vibration mitigation effort was also initiated which yielded improved bit runs and the identification of micro-tortuosity and weight transfer issues. Vibration mitigation resulted in the redesign of bottom hole assemblies (BHA) and the optimization of bent-housing steerable-motor angle settings. Rig rates have increased over time, along with the need for designer wells. Rotary Steerable Systems (RSS) were therefore implemented to address these issues. Initial attempts indicated that RSS were not able to overcome the formation tendencies in 3-D space. A detailed investigation resulted in the hypothesis whereby speeding up the RSS with a motor would provide enough side force with a push-the-bit system to overcome formation tendencies. Real-time Mechanical Specific Energy (MSE) measurements were used in conjunction with the implementation of a Powered Rotary Steerable Systems (PRSS) and revealed the fact that the full benefit of the RSS was not consistently realized (mostly due to the extreme nature of the drilling environment). As such, prototype extended-gauge PDC bits were designed in order to further reduce down-hole vibration, improve well bore quality and bit performance. The result has been sustained top quartile performance, a state drilling record and the continued growth of a mature field. Introduction Flournoy1 elaborated on the benefit of air hammer drilling in the shallow surface hole sections of wells in the Arkoma Basin. At the time of his publication optimization efforts resulted in rate of penetration (ROP) of 100-ft./hour versus the average of 25-ft./hour. Since then ROP's in excess of 200-ft./hour are not uncommon for air hammer systems. Although the surface hole sections are air drilled to this day, the primary reason is not penetration rate but rather the likelihood of mud losses with conventional mud systems. It should be noted that in recent years PDC bits run with mud systems just below surface casing routinely deliver similar performance. However, drilling with a mud system in the shallow surface section of the well has a distinct disadvantage in that severe losses of mud are likely. Unfortunately, gyroscopic surveys from surface hole sections which have been air drilled with hammers at high penetration rates have shown excessive dog legs and inclinations as high as 7-degrees in some wells. The result has at times been unpredictable drift of the well path which may not be an issue for shallow Red Oak wells but is certainly an issue for wells drilling to deeper depths. Most of the wells drilled within the last two years in the Red Oak Field required drilling from less than ideal locations atop mountains or drilling multiple target wells with tails below typical pay horizons. Improvements in seismic and geologic interpretation by the Sub-surface Technical Team resulted in designer wells (see Figure 1) with tight tolerances. The thrusted, faulted and folded nature of the formations in the basin made directional operations onerous and costly. Directional constraints coupled with the fact that air hammer drilling operations for the surface section of the wells provides very little directional control often results in directional operations beginning from an even less-desirable location. As a result ROP's in the air drilled surface section are often constrained in order to alleviate potential shallow dog legs for deeper wells.

The equivalent circulation density reduction tool (ECDRT) is designed to counter the increased fluid pressure in the annulus caused by friction loss and cuttings load by reducing the total hydrostatic head. The tool has a broad range of drilling applications, including: narrow pore/fracture pressure margins in deep water and their effects on casing setting-depth selection; wellbore instability; depleted reservoirs; and extended-reach wells. This paper describes progress on development and testing of a prototype ECDRT. The prototype was recently tested in a BP onshore U.S. Arkoma asset operation in southeastern Oklahoma. The primary objectives of the field trial were: determine ECD reduction performance; establish reliability in field conditions; and evaluate the ECDRT operational procedures. The test involved drilling 8.75-in. hole with the tool running inside 9.625-in. casing cemented at a depth of 4,500 ft. Performance was monitored continuously from a real-time display of surface and downhole measurements. Wellbore pressure management was clearly demonstrated in the field trial. The ECDRT consistently reduced ECD by about 150 psi, or the equivalent of about 0.7 ppg at 4,500 ft. Drilling performance was not limited in any way by the ECDRT. Fluid returns and wellbore cleaning were normal throughout the drilling operation. The ECDRT processed cuttings generated by the drilling at 100 ft/hr without difficulty. More than 500 ft of hole was successfully drilled before the tool was pulled because of difficulties with the directional drilling system. The final goal to evaluate ECDRT operational procedures was achieved as performance indicators on the surface worked reliably to diagnose the operational status of the tool. Post-well analysis showed that there were still some design issues to secure the longevity and sustained performance of the tool. The tool demonstrated the ability to manage annular pressure under actual drilling conditions. Introduction Managing downhole pressure is a critical element of most drilling jobs and becomes paramount under difficult conditions of deepwater and extended-reach drilling (ERD). The downhole pressure of circulating fluid is the sum of hydrostatic head (a function of mud density and cuttings loading) and frictional loss (a function of mud rheology, mud density, annular geometry, and flow rate). This paper describes the development of a downhole tool for reducing the ECD of circulating mud. It covers the design and testing of a prototype ECDRT that is valuable for use in managed-pressure drilling (MPD) applications, both onshore and offshore. The objective of ECD reduction is to minimize the effect of pressure loss caused by friction so that downhole pressure of circulating drilling fluid is nearly equal to its hydrostatic pressure. Some of the benefits of ECD reduction are: ability to drill challenging wells to their target depths; extended casing shoe intervals; increased safety margin between fracture gradient and actual ECD; improved rates of penetration (ROPs); and enhanced wellbore stability.1 In recent years several new technologies for MPD have been developed. Some of the new technologies for MPD are: dual-gradient drilling system2; annular backpressure control system3; continuous circulation system4,5; controlled rheological properties of drilling fluids for specific application6,7; and a downhole pump.8 The ECDRT is a portable tool that can be installed in the drillstring, as needed, by making a short trip. The ECDRT is located in the vertical section of the well, starting at less than 700 ft from the surface. This relatively shallow placement of the tool is significant, as it not only allows for rapid installation but ensures a limited effect on drilling activities. Deployment of the ECDRT requires virtually no rig-up time. Lessons learned from technology trials and successful field trials have been incorporated into the current design. The detailed results from the most recent trial in southeastern Oklahoma are presented in this paper together with the forward plan to make the technology available to the marketplace.