Completion methods used in the deep Anadarko Basin have varied a great deal over the past several years. Due to an active exploration program in the basin, Sohio Petroleum Co. formed a Springer task force group to evaluate past methods and to develop and refine deep completion techniques in the Morrow and Springer formations. This group formulated guidelines based upon published literature and past experience of the group members. The guidelines were implemented in the field and modified as more data and knowledge were obtained, resulting in a specific set of guidelines now used on all Morrow and Springer completions. There are a number of case histories that illustrate the evolution and reasons behind the specific guidelines, which will be listed.
Member SPE-AIME Abstract This paper explains the basic concepts and techniques necessary in optimizing and improving a turbine/diamond bit drilling application. Recent turbine/diamond bit drilling experience in the Morrow Formation of the Anadarko Basin indicates that a linear relationship exists between penetration rate and turbine output power available at the bit. Turbine output power is a linear function of the mud weight but more importantly, it is a function of the flow rate raised to the third power; therefore, slight increases in flow rate will yield significant increases in turbine output power. The increased turbine output power allows a higher bit weight which normally results in an increased penetration rate. Actual field data is presented penetration rate. Actual field data is presented which supports these relationships. Since fluid flow rate is of primary importance this paper describes techniques for maximizing flow rate. The importance of lithology is also presented. Finally, turbine/ diamond bit drilling economic evaluation is described. Introduction Optimizing a conventional turbine/diamond bit drilling application for straight hole drilling requires a basic understanding of turbine operating characteristics and how they influence penetration rate. Exxon Company, U.S.A.'s penetration rate. Exxon Company, U.S.A.'s Mid-continent Division has had over twenty five turbine/diamond bit applications on eleven wells in the Anadarko Basin for an average 220 percent increase in penetration rate over previous button bit penetration rate. Turbine/diamond bit applications have been successful in both 6.5 inch and 8.5 inch hole sizes in a variety of formations including the Springer, Redfork, Morrow and Granite Wash. Dispersed fresh water type mud systems ranging in weight from 13.3 ppg to 17.9 ppg have been used in these turbine/diamond bit applications. Diamond bits employed have been primarily premium stone, set with 6–8 stones per caret (SPC), with gauge length extended for per caret (SPC), with gauge length extended for turbine drilling. The turbines used in these applications are manufactured by two different companies and are turbines with turbine drive stages and not positive displacement "Moineau" type motors. The majority of Exxon's experience has been in 6.5 inch hole sections of the Morrow Formation and it is data from these applications which is presented in this paper. A drill test was presented in this paper. A drill test was conducted during one of these applications to determine the relationship between penetration rate and turbine output power. An analysis of this operational data, especially the drill test demonstrates a linear relationship between turbine output power and penetration rate. This data also emphasizes the impact that flow rate has on turbine output power and resulting penetration rate. penetration rate. This paper begins with some background information on turbine operating parameters, then a presentation of Exxon's Morrow turbine/diamond bit field experience and finally discussions on flow rate optimization, lithology and economic evaluation. TURBINE/DIAMOND BIT OPERATING PARAMETERS Turbine Output Power The key consideration in optimizing turbine/ diamond bit drilling is to maximize the turbine output power, this is supported in the next section by actual field data. The turbine output power in a drilling system can be determined by the following three equations: (1) (2) P. 55
Regions of western Canada comprise tough interbedded formations of hard sandstone, siltstone, shale and chert, which create great challenges for directional drilling applications. Historically, using conventional tungsten carbide insert (TCI) rollercone drill bits to drill a directionally placed wellbore trajectory has resulted in low penetration rates and short runs due to the impact of high cyclic loading and damaging hole-wall contact on the bits. With WOB being preferentially loaded on the heel and adjacent heel area of the roller cone cutting structure during directional drilling, cutting structure breakdown is accelerated and seal failures occur. Additionally, rigorous hole-wall contact increases gauge and shirttail wear. Extensive research, testing, and development have produced TCI rollercone bit designs that have addressed these major challenges. A multitude of design iterations have resulted in a new TCI rollercone drill bit that includes innovative cutting structures for improved durability and ROP, enhanced OD and leg protection to ensure bearing integrity and gauge-holding ability, and stronger materials and processes to withstand high cyclic loading of directional drilling. Drill bits designed with these features have been successful in increasing average footage per run by 121% while improving penetration rates modestly vs. offset drill bit runs in the western Canadian regions, which include Saskatchewan, Alberta, and British Columbia. Additionally, one-bit runs, as opposed to two or three, are now possible in builds to horizontal in many applications, thus reducing overall drilling time by over 25%, and significantly reducing drilling costs. This paper will detail the directional TCI rollercone drill bit design features and technologies used as well as field results and case studies from Canadian-specific markets. Introduction The Growing Need for Directional Drilling More and more oil and gas wells throughout Canada are being drilled directionally or horizontally. There are many reasons why Canadian operators are choosing to drill a well directionally, including:Thin reservoir formations—Often, the vertical thickness of a formation to be produced is quite thin such that a borehole drilled vertically through the formation would have very little surface area downhole from which to produce. By drilling the well horizontally in the reservoir formation, a much larger surface area is exposed and production potential is greatly increased.Restricted surface access—Often times, target formations to be drilled lie below areas that a drilling rig cannot access. These areas include environmentally sensitive areas, lakes or rivers, man-made structures, or areas for which the owner of the surface access rights does not want to grant access. This problem is avoided by setting up the drilling rig adjacent to the desired surface area and directing the wellbore laterally to target the zone of interest.More efficient exploration—Many wells are now being drilled in areas that have been produced in the past, but not completely exploited. By drilling directionally, the operator is able to locate and produce zones that were previously undiscovered or bypassed.
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