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An operator in the Taranaki Basin, offshore New Zealand, employed resin sealant technology in a recent shelf development to isolate the vertical pilot hole from the production formations. This paper details the success of the operation in which the resin sealant was placed in the pilot hole through the drilling bottomhole assembly (BHA) by using a pump and pull technique without needing to trip out to change the BHA, resulting in time and cost savings.
The operator drilled a pilot hole to gather petrophysical data to assess the geological model and formation pressures of the field. Afterward, the pilot hole was to be permanently abandoned, blocking any flow between the pilot hole and the horizontal production wellbore. Conventional practice would be to pull the drilling BHA to surface and then trip in with a dedicated cementing work string to abandon the pilot hole with a series of cement plugs. In this case, abandonment was executed by placing resin sealant in the pilot hole through the drilling BHA without tripping out and changing the BHA.
The dynamic tools on the BHA were unaffected by the resin and drilling continued without incident. When the BHA was pulled out and examined, there was no evidence of the resin within the drilling/placement BHA string. The operator commenced drilling in the main wellbore, and set a 9 5/8-in casing at 3055 m measured depth (MD). The well has since been completed, and the lack of any observed pressure in the production string annulus indicates that full isolation was achieved in both the pilot and main production wellbores. This approach has since been adopted by the operator as the standard procedure for the remainder of the wells in the program.
Using resin technology to abandon a pilot hole through the drilling BHA allowed the operator to avoid tripping in with a dedicated cementing work string, resulting in reduction of both time and overall cost.
For the first time in ADCO, and the UAE, a window was opened in Super 13CR 7 inch casing in well QW-XY. Extensive pre-job planning, two way communication between ADCO and Baker Hughes, and flawless job execution were the key factors for the success which allowed ADCO to immediately reach the reservoir, saving significant time and costs versus the typical window in the 9 5/8 inch casing.
The main objective was to avoid cutting the window through the 9 5/8 inch casing to leave space for the ESP completion to be installed deeper for enhanced oil recovery and extending the well life. This also saved resources to drill 8-12/" section including OBM and 7 inch liner and its related accessories that were going to be required in case of the 9 5/8 inch casing window. The team decided to take the challenge presented in the stiffness of the Super 13CR material and the deviation at the window depth to save Rig days and resources.
This operation utilized Path-Master whip stock and Silverback milling technology to successfully open the window and drill the required rat-hole in one trip. Another reaming trip was carried out to ensure seamless reentry with the drilling BHA later on. Teamwork and cooperation are the keywords that made this operation possible; with Baker Hughes technology and ADCO's innovation.
This paper describes the first ever window opeing thorugh 7in S13CR in the UAE. This includes planning, risk assessment, the challeges, procedures and the conclusion. A detailed cost-benefit analysis is presented between 9-5/8" convetional window opeing compared with 7in window.
Legarth, B. (Brunei Shell Petr. Sdn Bhd) | Dustin, S. (Brunei Shell Petr. Sdn Bhd) | Montero, J. (Brunei Shell Petr. Sdn Bhd) | Walker, J. (Schlumberger ) | Mulligan, R. (Schlumberger) | Maeso, C. (Schlumberger )
Copyright 2013, SPE/IADC Drilling Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 5-7 March 2013. This paper was selected for presentation by an SPE/IADC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE/IADC copyright. Abstract Some of the oil fields offshore Brunei are characterized by complex reservoir geology. This requires the drilling of highcomplexity, tortuous 3D horizontal wells referred to as "snake wells" for optimal reservoir drainage. These wells deliver an ultimate recovery equivalent to multiple horizontal wells drilled in the same structure. This development concept was chosen as the most beneficial with the business value drivers for the Selangkir Iron Duke (SKID) project. Over a period of several years, drilling performance had improved but plateaued and still contained hours of nonproductive time (NPT), including hole conditioning wiper trips, rough drilling causing bottomhole assembly (BHA) failures due to vibrations, troublesome trips, and even lost production due to stuck-pipe incidents. In previous "snake well" drilling campaigns multiple additions to the BHA design to overcome tight hole problems had seen an ever more complex and rigid BHA being adopted, but without the required NPT or well cost reductions.
Pardy, Craig (Husky Energy) | Akinniranye, Goke (K&M Technology Group) | Carter, Mackenzie (Schlumberger) | Crane, Gerry (Husky Energy) | Wishart, Lisa (Husky Energy) | Krepp, Tony (K&M Technology Group) | Foster, Brandon (K&M Technology Group)
Copyright 2013, SPE/IADC Drilling Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 5-7 March 2013. This paper was selected for presentation by an SPE/IADC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE/IADC copyright. Abstract The White Rose field and its satellite extensions have posed significant drilling challenges. Ability to reach the reservoir targets has been challenged by high levels of downhole shock and vibration and torque limitations of certain drillstring components. In earlier wells, the levels of shock and vibration encountered while drilling in both the intermediate and production hole sections resulted in issues including low rates of penetration, premature bit wear, damaged tools and unplanned trips for downhole tool failures. A number of issues contributed to drilling challenges, including weather, ice encroachment, and rig equipment challenges. Extensive drilling and completion design and operational improvements were achieved over a period of 3 years from 2009 to 2012. These improvements included changes to, well trajectory designs, drillstring and bottom hole assembly (BHA) designs, procedures for torque-and-drag management, fluids designs, and lower completion design. These combined efforts significantly reduced downhole-related nonproductive time, despite a substantial increase in well complexity.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142431, "A Practical, Application-Based Guide to Borehole-Enlargement- Tool Selection," by J. McCarthy, SPE, J. Rebellon, SPE, S. Barton, SPE, and R. Rambhai, National Oilwell Varco, prepared for the 2011 Brazil Offshore Conference and Exhibition, Macae, Brazil, 14-17 June. The paper has not been peer reviewed.
Borehole enlargement (BHE) has become commonplace. Still, it can be very demanding from planning and execution points of view, particularly in deepwater basins. To address the needs of challenging applications, a variety of tools has been developed. The two primary BHE methods use either eccentric or concentric tools. Depending on the type of well that is being drilled and the formation characteristics, the engineer must choose the optimal bottomhole assembly (BHA) and drilling parameters for successful BHE. Understanding the application is critical in delivering a successful BHE operation.
BHE technology has enabled exploiting complex and unconventional reservoirs. Heavier and larger casing strings are set at greater depths, allowing operators to obtain improved recovery rates from the reservoirs. Each application must be analyzed thoroughly to provide the best design. Proper selection of BHE technology is critical. Improper selection of BHE technology can lead to complete loss of the well.
For this paper, a BHE tool is one that can expand a borehole beyond the diameter at which it can pass through. Typically, this means creating a borehole larger than the inner diameter of the casing already in place. BHE tools are defined by their pass-through diameter and their expanded diameter, or drill size. BHE tools can pass through casing (or other restriction) to create a larger-diameter hole than the restriction and then can be retrieved safely from the well.
To select the appropriate BHE technology, the engineer must understand the intricacies of the application and configure the drilling system to provide the best results in an economical and safe manner. Several factors affect this selection, some of which are set before the operation begins. Factors such as economics, rig capabilities, borehole quality, and drive type or system used to drill the well must be reviewed during the selection process.
Fig. 1 shows the two primary categories of BHE tools: eccentric and concentric. Tools can be placed in the drillstring at two locations (at the bit or up in the drillstring). A third category of tools, the hole opener, often is thought of as a BHE tool, but these tools cannot generate a borehole larger than the minimum restriction of a well, so they do not fit the definition used here. However, they are sometimes used in conjunction with BHE tools, as a secondary cutting structure to provide a solid platform for the BHE device.
Many hole-enlargement products are available, each of which fits a particular application. The simplest are the fixed-cutter designs.
In the past 10 years bicenter bits have become a popular tool to enlarge a bore-hole section beneath a section of a smaller diameter. In the mid 1990s bicenter bit design attracted attention from drill bit manufacturers as a solution to extend a well by sidetracking out of small-diameter casing and liners and providing a larger hole. As stated by Denham and Fielder (2000), deepwater drilling activity was also increasing during this period requiring multi-diameter casing strings. Bicenter bits enabled the operator to set multiple casing strings by providing a larger hole than conventional concentric bits. Geometric balancing, force balancing, and design features using chamfered cutters and rounded tungsten carbide inserts were used in bicenter-bit design to reduce lateral vibrations and improve directional steerability while increasing durability. In the late 1990s a bicenter bit capable of drilling a casing shoe was introduced, allowing the driller to drill-out inside of liner hangers and casing float equipment, eliminating the need of making a trip to drill out with a conventional bit and pick up a bicenter bit. Current bicenter technology is in its fifth generation and a sixth generation is in development.
Stronach, Graham R. (Smith International Inc.) | Voden, Gerre S. (Smith International Inc.) | Hubbard, Jeffrey S. (Smith International Inc.) | Ming, C. Michael (K. Stewart Petroleum Corp.) | Northcutt, J. Craig (Basin Enterprises)
In a technically challenging deep well in the Anadarko Basin, the importance of engineered bottom hole assemblies (BHA) and "fit for purpose" drilling equipment were key factors in achieving project success. This paper will discuss the BHA analyses carried out prior to the start of the well, including prediction modeling and contingency considerations. Establishing a unique formation deviation control index for the well bore is demonstrated to be an important element in the decision making process of BHA design. Post-well analysis results are also discussed as are the lessons learned. The importance of establishing and maintaining consistent standards for equipment selection and the subsequent results are discussed. To manage a large amount of data gathered during drilling operations, a new system of data management was employed to ensure that the data gathered was in a useable format, and could be used for concurrent and future operational improvements. The results of field data, computer prediction modeling and the system of data management are discussed in this paper.
A non-directional well with a total depth of approximately 25,000 feet to intersect the Hunton formation was planned in the South West New Liberty field of Beckham County, Oklahoma. Twelve previous wells drilled by five different operators in this area were reviewed as part of the planning process for this well. Numerous technical challenges were identified including casing design, completion requirements and well bore instability. Two additional challenges that were identified are the primary areas of focus in this paper, namely:
Control of well bore deviation and minimizing dogleg severity. This was a critical concern in particular for the 11-7/8 inch intermediate casing. The control of deviation and dogleg severity was also identified as important factors in minimizing casing wear as the well depth increased.
Avoidance of down hole drill stem failures including both drill pipe and BHA components.
Both of the above factors were noted to be serious and costly problems in the offset wells studied. Therefore, the following specific processes were developed and utilized to address these concerns.
A model was established for assisting in the prediction of BHA performance. This formed the basis for the decision making process of BHA configuration.
Criteria were also established for assessing the suitability of equipment to be used in the drill stem. All drill stem equipment, regardless of the supplier, was assessed in accordance with common and stringent criteria.
Equipment evaluation was carried out on location at periodic intervals to review its condition and to determine if changes to its design and inspection criteria were required.
Rig site personnel were also given scheduled awareness training, both before and during drilling operations.
A data management process was also initiated to capture drilling data and equipment evaluation results during operations. This allowed optimizations to be made concurrent with drilling operations.