PDC Applications in the Gulf of Mexico With Water-Based Drilling Fluids

Abstract

Summary. This paper presents the results of a recent study conducted to determine application and operating requirements for polycrystalline diamond compact (PDC) bits in the Gulf of Mexico. This study evaluated PDC-bit usage in Miocene sections of the Gulf of Mexico and has resulted in a saving of more than $1.4 million based on 22 bit runs. As a result of this study, operational guidelines for PDC bits were established and drilling costs per foot were significantly reduced. In addition, a relationship was found between shale reactivity, strength, and density. This proved to be an effective aid in bit selection and determination of hydraulic requirements and verified the results of the study. Introduction While a well is being drilled, the rate of penetration (ROP) usually decreases with depth. ROP's with conventional rock bits are affected by tooth and bearing wear, whereas PDC bits are minimally affected. On the basis of advances made with PDC bits and new failure-mechanisms theories, PDC bits have successfully reduced cost per foot in basins outside the Gulf of Mexico.A majority of the footage drilled in the Gulf of Mexico was with rock bits. Past PDC applications were limited primarily to deep hole sections, smaller hole sizes, or wells drilled with oil-based muds. It was recognized that rock mechanics laws did not support the previously mentioned PDC limitations. PDC bits should out-perform rock bits because most shales fail easily in shear and PDC bits always operate in a shearing mode. in addition, PDC bits are known to drill better in water-based muds when shale shear strength is high. A paradox between physical law and practice existed. A more thorough understanding of the effect of mud type, formation composition, and hydraulics would be required to find a solution.A study was initiated in May 1985 to determine how to apply PDC technology in the Gulf of Mexico. The Tenneco Real Time Data Center was used to monitor and to collect drilling data for this study. This also allowed bit performance to be related to lithology and electric log data. The runs were made in a water-based drilling fluid with large- diameter cutter- and fishtail-type PDC bits. Typical savings, vs. those with conventional milled-tooth rock bits, ranged from $30,000 to $90,000 per run. The longest continuous run was 5,685 ft [1733 m] (6,665 ft to 12,350 ft [2031 to 3764 m]) at an average ROP of 90 ft/hr [27 m/h] (Table 1). The success experienced on these PDC bit runs was a result of matching proper bit design and hydraulics to formation composition, using the relationship between shale reactivity and bit performance. This paper examines the relationship between these previously mentioned variables with respect to PDC performance. It will also address design and operational considerations essential to successful water-based PDC applications in the Gulf of Mexico. Theorized Rock-Failure Modes The manner in which a rock fails is important in bit selection. This failure mode can be brittle or plastic depending on the confining stress. Conventional theories used in the calculation of confining stress assumed that the pore pressure within shale remained constant. If this were true, however, it is unlikely that the confining stresses would be high enough to cause the shale to become plastic. Recent data and rock failure theories support the position that most shales fail in a plastic condition. This plasticity was confirmed from field data.A theory explaining this behavior was presented in a paper by Warren and Smith, which examined localized stress conditions at the bit. This theory is predicated on stress relieving the original shale, which causes a PV increase. This stress relief is caused by replacement of the heavier overburden with a lighter mud. This is normally the case because most mud weights are less than 20 lbm/gal [less than 2397 kg/m3], which approximates overburden density. Because shale is impermeable, there is no pressure maintenance through fluid movement, and because the of PV increase, some pore-pressure loss is expected. This localized loss of pore pressure will increase confining stress on the shale near the bit. The magnitude of the confining stress depends on the fluid type trapped in the shale. If a compressible fluide.g., gasis contained in the pore spaces, the pore-pressure loss within the shale will be insignificant, If an incompressible fluide.g., wateris contained in the pore space, a significant amount of the original pore pressure is lost. This results in very high localized confining stress and causes the mechanical properties of the shale to change. This phenomenon is modeled with a Mohr envelope. Because these theories have established that most shales are plastic and fail easily in shear, it follows that a PDC bit, which is a drag-type bit, should be the optimum bit to use. Bit-Design Characteristics For the purpose of this study, PDC bits are broken down into three general classes:conventional PDC bits made with 1/2-in. [1.27-cm] cutters found on familiar diamond-bit profiles (Fig. 1),fishtail PDC bits made with 1/2-in. [1.27-cm] cutters on historic fishtail drag-bit profile (Fig. 2), andlarge-cutter PDC bits made with large (1, 1 1/2-, or 2-in. [2.54-, 3.81-, or 5.08-cm] -diameter) cutters with a nozzle for each cutter (Fig. 3). There are several styles with each of the three classes of bits, but all styles within a class will exhibit similar features in terms of overall design variables. The following general design variables are considered: Cutter Exposure. Exposure is defined as distance of the bit face to the cutter tip. Exposure can be achieved either with cutter size or with a structure on the bite.g., steps and blades-to elevate the cutters above the rest of the bit face. Conventional PDC bits used as a baseline show how the other two bit classes achieve an increase in cutter exposure. Fishtail bits use a drag blade, or exaggerated junk slot, to elevate the cutters from the bit body. Bits with large-diameter PDC cutters use the cutter size to increase the exposure. Profile. Profile is the shape of the bit or the structure on which the cutters are placed. Figs. 1 through 3 show a variety of profiles within each class. SPEDE P. 117^

Effects of PDC-Bit Selection and Mud Chemistry on Drilling Rates in Shale

“…Clearly, some mud types are better performers than others. 5. Of the nine fluids tested, the diesel-and ester-based muds exhibited the highest ROP's.…”

“…Feenstra 4 reviewed the work on PDC-bit drilling with waterbased muds in shales with particular emphasis on the conditions that promote bit balling. Gault et al 5 developed guidelines for use of PDC bits with water-based muds in shales. They specify PDC-bit design and hydraulics depending on the cation-exchange capacity (CEC) of the shale to be drilled, No attempt was made to evaluate bit performance by type of water-based mud.…”

Eggbeater PDC Drillbit Design Eliminates Balling in Water-Based Drilling Fluids

“…The Appendix gives brief descriptions of these formations, and Table 1 gives petrophysical data that may be used for correlation with the drillability. 10,11 Blade-type and fishtail bits are used to drill these formations; however, use of these bit types involves a risk of total bit balling. So far, fishtail bits are considered to have the best potential for drilling in these formations.…”

Status of Polycrystalline-Diamond-Compact Bits: Part I Development(includes associated papers 19032 and 19900 )

“…These are generally held to be responsible for the balling tendency of PDC bits in a waterbased-mud environment. Gault et al 21 went as far as to relate a PDC bit's drilling rate in U.S . gulf coast shales and the bit's hydraulic requirements to the clays' cationic exchange capacity (CEC) in a water-based-mud environment.…”

“…21 have made an attempt to relate the bit selection to CEC values of gulf coast shales in a water-basedmud environment, a scheme worth testing. Such soft-formation bits may also be effective in soft, impermeable formations other than reactive shales .…”