This paper describes Qatar General Petroleum Corporation's (QGPC) reduction of overall drilling cost through implementation of optimized pairing of Turbines, Positive Displacement Motors and Conventional Rotary Drilling Assemblies, with Milled Tooth, Tungsten Carbide Insert (TCI) and Polycrystalline Diamond Compact (PDC) bits. The overall performance of given techniques, i.e., High Performance motors with TCI bits, Steerable Turbines with PDC Bits etc., was compared using the expected value cost analysis technique such that the beneficial or detrimental effect of any bottom hole drilling assembly on the overall drilling operation in terms of cost, such as poor hole conditions, high incidence of stuck pipe, lower drilling fluid cost etc., was taken into account.
Introduction
In 1993 a comprehensive cost per foot analysis was conducted on the last 200 bit runs made by QGPC offshore in the 26" Conductor, 17-1/2" Surface, 12-1/4" Intermediate and 8-1/2" productions hole sections. The analysis indicated that footage cost reductions over 30% could be made by simply utilizing the bit brands and types which historically generated the lowest cost in each geologic section. During this investigation it was also noted that rotational method. i.e., Conventional Rotary, Positive Displacement Downhole Motor (PDM) or Turbine had significant impact on footage cost and drilling performance. Further, the frequency and severity of downhole problems such as inadvertent pack-offs, stuck pipe and twist-offs tended to be symptomatic of certain Bit/Motor bottom hole assemblies as opposed to rare, unrelated events.
The historical drilling data was then used to optimally pair the rotational technique with the proper bit type to achieve minimal overall footage cost. The expected value cost analysis method was employed in conjunction with an expanded version of the conventional footage cost equation to make the comparisons.
The use of Straight Hole Turbines with IADC Series 1.1.4. and 1.3.5. Milled Tooth Rock bits in the 17-1/2" surface hole, initiated in 1979, solved the problem of repeated drillstring twist-offs whilst drilling the H2S bearing surface formations such as the Umm Er Radhuma, Simsima and Laffan, due to Sulfide Stress Cracking. Utilization of the Turbines with downhole rotational speeds up to 800 rpm, generated high penetration rates in the surface hole, whilst the surface rotational speed for the drillstring above the turbine could be run as low as 50 rpm. The aforesaid reduction in drillstring rotational speed from the normal conventional rotary speed of from 90 to 150 rpm to 50 rpm using the Turbine, significantly reduced drillstring stresses and the incidence of twist-offs in the surface hole.
The major drawback with the Turbine however was that if a twist-off occurred, the Turbine BHAs were sometimes unretrievable and the surface hole had to be sidetracked, with the associated lost in hole and sidetracking cost. Another drawback was limited bearing life on the Rock bits used at the Turbines high rotational speed. One trial of a 17-1/2" PDC bit on a Turbine was made but deemed uneconomic.
Expected value cost analysis of Rotary/Rock Bit, PDM/Rock Bit and Turbine/Rock Bit combinations indicated that a Rock Bit run on a conventional rotary assembly would now offer the lowest cost. Reduction in the frequency of twistoffs with conventional rotary assemblies in 1993 as compared to 1979 was attributed to the availability of better quality drillpipe, drillstring components and tubular inspection practices.
The requirement for nudging out from the 9-slot well head jackets in the 17–1/2" surface hole mandated that a bent housing PDM be used for at least the first part of the surface hole on most of the wells. P. 75^
