The presence of fractures in reservoirs can have a large impact on short and long term production. Electrical imaging tools have a long history in the identification and quantification of fractures in boreholes drilled with water base muds. These tools are particularly sensitive to conductive fractures. The width (also known as aperture) of open fractures is calculated by a well-established equation, relating the fracture width to the excess current measured by the imaging tool (Luthi and Souhaité, 1990). Both mud resistivity and background resistivity of the formation need to be known or measured. The equation was derived from 3-D finite element modeling of the borehole imaging tools of the time. Recent work has revisited the fracture aperture calculations. The work has verified the approach for electrical imaging from modern wireline tools and extended the principle to Logging While Drilling (LWD) tools. A twofold approach has been taken for the work. Firstly 3-D finite element modeling had been carried out. This includes detailed modeling of the tool sensors' geometry and the analysis of the electromagnetic responses when the sensors are passed in front of a range of fracture widths. The modeling is complemented by a series of physical experiments carried out at Delft University. Setups utilized either a wireline pad or an LWD sensor from the relevant imaging tools. The sensors were traversed across two blocks separated by a precisely measured gap. Measured excess current relates to the fracture apertures and verifies the theoretical modeling work. This combined work confirms the equation for the fracture aperture calculation. In addition the coefficients for both the modern wireline and LWD electrical imaging tools are determined. Workflows for the quantification of conductive fractures identified on borehole images have been refined and implemented. Fractures are commonly not continuous across the borehole. The workflow includes a fast automatic extraction of both discontinuous and continuous fracture segments. Fractures are grouped into sets based on relevant criteria (such as orientation). Apertures are calculated using the relevant tool coefficients. The fracture density and porosity are then accurately computed along the well. This enables quantification and characterization of the fracture network, including a fast and easy recognition of intervals with specific aperture or porosity ranges. The workflow is demonstrated by examples.

Horizontal wells give a great opportunity for maximizing the potential of unconventional resource play developments by providing enhanced reservoir contact but present multiple challenges in the process due to the heterogeneous nature of the unconventional reservoir rock. This study covers the implementation of an integrated completion and production workflow to optimize a horizontal well development project in the Delaware Basin located in Reeves County, Texas. By undertaking a vertical well pilot logging program, the acreage was evaluated for petrophysical and geomechanical properties using advanced geo-chemical and full-wave sonic tools to quantify reservoir quality (RQ) and completion quality (CQ), respectively. Detailed fracture simulations were performed at multiple depths to locate the optimum landing point that maximized reservoir contact. Incorporating the key findings of the wellbore stability analysis, the well was geo-steered using a rotary steerable system (RSS) and a logging-while drilling (LWD) resistivity tool that placed 100% of the lateral in the target zone. Further completion simulations were performed to determine a perforating and staging strategy which would optimize the number of stages. The flow-channel fracturing technique, which provides a novel approach for achieving fracture conductivity, was also implemented on the studied well to significantly improve the effectiveness of the fracture stimulation treatment. Fracture diagnostics, detailed post fracture modeling, and production analysis techniques, which utilized rate-transient analysis and history matching, were performed to provide better understanding of the effectiveness of the stimulation treatments (fracture lengths/conductivity), thereby allowing further optimization of the stimulation program. This study has demonstrated how the implementation of an integrated design and evaluation workflow can optimize the overall well production performance as well as reduce drilling and stimulation costs in unconventional resource play developments.

The low formation unconfined compressive strength (UCS) and low abrasiveness in build and horizontal sections of a Marcellus shale well, relatively green PDC and roller cone dull bits, and the desire to drill fast at high build rates with one bottomhole assembly (BHA) facilitate the use of PDC bits with aggressive cutting structures and new torque management technology. Aggressive PDC cutting structures that inherently drill at higher ROP generate high differential torque and erratic toolface leading to insufficient build rates. If lower energy input to the PDC or less aggressive bits are employed to manage torque, instantaneous rate of penetration (ROP) can be lower. Along with this, drillstring friction can result in less consistent and lower weight on bit (WOB), or high differential torque requiring lowered operating parameters and additional toolface resetting. Due to these issues, instantaneous ROP and feet per day will be lower. This can also affect downhole tool loading and reliability and also toolface control, which can reduce build-up rate (BUR) capacity. In build sections where PDC bits do not demonstrate planned build rates, roller cone bits are run to achieve the planned well path. The roller cone bit is used to manage torque and a unique tooth design is used to increase ROP over traditional bits. This paper investigates the implementation and optimization of new torque management technology combined with the use of managed cutting structure aggressiveness of PDC bits and a unique roller cone bit cutting structure to determine the effects on operating parameters, toolface control, build rates, well path trajectory, cutting structure efficiency, feet drilled per day, instantaneous ROP and time savings. Employing the new torque management technology on optimized, aggressive PDC cutting structures can result in faster drilled sections due to higher instantaneous ROP and less time spent in non-productive steering operations.

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In July 1995 the first coiled tubing insert gas lift string (CTIGLS) to be run in the North Sea was installed in BP Exploration's Forties Field. Following 15 months of successful production the completion was worked over in November 1996. This is only the fifth completion of its kind to be run world-wide and the first to be worked over. The project was a commercial success, even though production did not meet predicted targets. Initial corrosion predictions suggested the completion should be pulled within six months. However due to good performance of the well and increasing confidence in the integrity of the completion the asset decided to continue production. The well was worked over some fifteen months into production. As with all new projects problems were encountered, especially during the workover, which added to the cost of the operation. The lessons learned from our experiences will be invaluable in planning any future operations of this kind. The complete operation was planned and executed by the Forties Well Engineering Alliance, involving extensive input from several service companies along with BP. Introduction The Forties Field has been producing since 1975. Initially all producing wells were installed with 7" completions and produced naturally at over 20 Mbd dry oil. As the reservoir pressure declined and water production commenced the completions were downsized to 4–1/2" tubing in order to continue natural flow (Fig 1). Again water cuts rose to the extent that natural flow was no longer possible for many wells and in 1989 an artificial lift programme was initiated to continue production. Gas lift was the preferred method of artificial lift. Completions were redesigned to allow 5–1/2" production tubing to be run with 2–3/8" gas injection string in the casing (Fig 2). The original casing utilized buttress connections which required replacement with premium connections in order to provide a gas tight annulus for the injection gas. This operation was lengthy and expensive, requiring the old casing to be cut and pulled and new casing to be installed, also to allow room for the two strings. Unfortunately the carbon steel tubulars which served so well for the first 15 years of the field life performed very poorly with the increased water cuts, CO2 and sand production. Within two years it became apparent that the completions and liners would have to be replaced with higher grade metallurgies. This resulted in suspension of the gas lift conversion programme to re-assess the way forward. The conclusion was that all future gas lift wells would require sidetracking to allow installation of a new 13% Chrome liner. Insert liners were not at the time acceptable due to the reduced ID and flow restrictions. For most wells the sidetracks were to a bottom hole location some 50m away from the original location. In some cases the oil remaining at that location did not justify the ca 2.5M cost of the sidetrack so the original hole would be abandoned and the well would be drilled to a new bottom hole location somewhere else in the field. This resulted in considerable amounts of oil left in place but un-produced. A cheaper method of artificial lift was required to access the remaining oil. One option looked at by the Forties team was coiled tubing insert gas lift completions. The options available for installing an insert string and to change the lift mechanism of the well was:–Non-upset tubing–Flush pipe–Coiled tubing–Upset Tubing P. 465^