Review of PDC Bits Run With Invert-Emulsion Oil Mud in Shallow South Texas Wells
- G.M. McClelland (Exxon Co. U.S.A.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling Engineering
- Publication Date
- June 1986
- Document Type
- Journal Paper
- 193 - 200
- 1986. Society of Petroleum Engineers
- 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.6.1 Drilling Operation Management, 4.1.5 Processing Equipment, 1.8 Formation Damage, 1.11.4 Solids Control, 1.10.4 Onshore Drilling Units, 2.4.3 Sand/Solids Control, 5.3.4 Integration of geomechanics in models, 1.14 Casing and Cementing, 1.5 Drill Bits, 4.1.2 Separation and Treating, 1.6 Drilling Operations, 1.5.1 Bit Design, 1.11 Drilling Fluids and Materials, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc)
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Summary. This paper examines 56 polycrystalline-diamond-compact (PDC) bit runs, discusses the evolution of the PDC bit, and recommends guidelines for selecting the most economical bit design for shallow south Texas wells drilled with invert-emulsion oil mud. From March 1981 to April 1984, our South Texas Div. Drilling documented 88 PDC bit runs with invert-emulsion oil mud in shallow south Texas wells. These PDC bits primarily drilled soft Frio formations of sand and shale to less than 12,000 ft [3660 m] total depth (TD). Throughout this time, PDC bit design continually improved, providing progressively greater time and cost savings. Field data indicated that improvements in bit material, body design, cutter placement, and operating procedures have increased rates of penetration placement, and operating procedures have increased rates of penetration (ROP's) and bit life, thus decreasing drilling costs.
A PDC is composed of a synthetic diamond attached to a tungsten carbide substrate by a high-temperature/ high-pressure (HTHP) brazing or diffusion bonding process. The synthetic diamond crystals provide hardness and wear resistance, while the tungsten carbide provides strength to the PDC. When attached to the face of a bit, they can shear formations as effectively as original drag bits, especially when used in conjunction with invert-emulsion oil mud. Invert-emulsion oil mud consists of a continuous oil phase, such as diesel, with water emulsified in the oil as phase, such as diesel, with water emulsified in the oil as a discontinuous phase. When used in the correct circumstances, invert-emulsion oil mud is beneficial to the operation of PDC bits. Benefits include decreased drilling cost per foot, increased ROP and bit life, inhibition of sloughing shales and bit balling, increased lubricity, and inhibition of formation damage and fluid loss. We first experimented with PDC bits in invert-emulsion oil mud in July 1980. The combination gained acceptance in shallow-drilling applications in Sept. 1981. Since then, 88 bit runs have been documented in shallow south Texas gas wells. A typical wellbore for drilling south Texas formations with PDC bits and invert-emulsion oil mud is illustrated in Fig. 1. A 12 1/4-in. [31.1-cm] surface hole is drilled to about 1,500 ft [460 m] with gel and fresh water, and 8 5/8- or 9 5/8-in. [21.9- or 24.5-cm] -OD surface casing is cemented in place. The surface-casing cement is displaced with 10.0-lbm/gal [1200-kg/m3] invert-emulsion oil mud. One or two rock bits are used to drill below surface casing, followed by one or more PDC bits to drill to TD. Typically, TD is approximately 9,500 ft [2900 m] and requires a final mud weight of 11.5 to 12.5 lbm/gal [1380 to 1500 kg/m3]. To optimize PDC bit performance, we developed operating guidelines for invert-emulsion oil mud in shallow drilling applications (Table 1). Numerous bit manufacturing companies offer many various designs of PDC bits to drill in invert-emulsion oil mud. The 56 bit runs detailed in this paper represent 19 different bit designs manufactured by nine companies. With such a large and varied choice available, it became necessary to develop guidelines to determine what bit characteristics are desirable and will help produce the most economical bit run possible.
The formations drilled by each PDC bit in this study were assumed to be identical within the three depth categories identified. Wells that drilled dissimilar formations or drilled to a depth greater than 12,000 ft [3660 m] were excluded. All invert-emulsion oil mud systems were assumed to be identical in this study. Except for HTHP fluid loss, the same general operating guidelines have been used since 1982. During 1982, we began lowering HTHP fluid loss to reduce mud costs because a lower HTHP fluid loss was found not to affect penetration rates adversely. Here, HTHP-fluid-loss testing parameters were 250 deg. F [121 deg. C] with a 500-psi [3.45-MPa] differential pressure. We assumed that all bits within a particular category of the PDC bit classification table (Table 2) were identical. The recommended PDC bit operating parameters were based on the average flow rates, weights on bit, rotary speeds, and bit pressure drops of the PDC bit runs in this study.
Our data were taken from 56 field runs in 52 wells in Kenedy, Brooks, and Hidalgo Counties, TX; the majority of the runs (87%) were in Kenedy County (Fig. 2). Each field run was drilled with a new PDC bit in invert-emulsion oil mud. Rerun bit performances are not evaluated here. This was the principal reason for eliminating 32 of the original 88 PDC bit runs documented. A particular PDC bit design is usually not purchased for its particular PDC bit design is usually not purchased for its rerun qualities, even though bit life is an important factor. Each PDC bit run was drilled by a rotary land rig.
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