Perhaps the bit is simply approaching the end of its useful life earlier than anticipated through unexpectedly high wear – in which case, at what point does it become less economic to continue drilling at low ROP and so POOH to pick up a new bit instead? The decision to POOH to change a bit that is perceived to be under-performing can be costly if the bit is subsequently found to be in workable condition and the trip was therefore premature. Unnecessary trips are a major source of non-productive time (NPT), so any trusted source of indicative information on bit condition adds valuable context and confidence to operational decision-making. Conversely, in some markets such as US land, there is a healthy market in redressing used bits which allows operators in relatively low-cost operations to recoup a notable portion of their bit expenditure; there is therefore commercial incentive to avoid running a bit until it is damaged beyond repair.
An additional consideration is the potential secondary NPT and financial risk caused by bit wear and loss of cutters: reduced ability to resolve incremental vibration potentially leading to costly damage to BHA components, reduced directional control leading to increased wellbore tortuosity, under-gauge hole and suboptimal well placement, and junk in hole.
So what real time metric can be used to inform decision-makers of the ‘tipping point’ at which objective commercial factors support pulling a dull bit, mitigating invisible lost time (ILT) through excessive prolongation of an ineffectual dulled bit run against reducing the risk of its potentially catastrophic failure? It is this last dilemma that the methodology described in this article will address.
When a new PDC bit is drilling efficiently, the energy imparted into the well construction process – in the form of WOB and RPM – is transferred effectively into rock destruction through the crushing action of the PDC cutters. Over time the cutters inevitably erode so that the wearflat area increases, which in turn increases the total contact area between bit and formation and therefore the rotational friction. This effect is further exacerbated if cutters wear to such an extent that the bit body matrix starts to come into direct contact with formation.
Rotational friction of such a worn PDC bit generates considerable heat at the bit face – industry research through modelling and test bench measurement shows that 800 - 1000°C is not unusual. At these temperatures, the hydrocarbon content of oil-based or synthetic-based drilling fluids, even hydrocarbon-based additives in water-based fluids, can be instantaneously thermally cracked in-situ as they transit this very localised high temperature (and high pressure) environment. The thermal decomposition of the saturated and aromatic hydrocarbons that make up diesel and other mineral oil components of drilling fluid produces fewer complex hydrocarbons, including simple alkene gases such as ethylene and propylene.
It is worth noting that at such temperatures, physical failure of PDC bit becomes a concern. The standard metallic flux used to braze PDC cutters into the circular pockets in the tungsten carbide body of a bit has a melting point of ~550°C, while the maximum thermal operating temperature for standard PDC cutters is ~750°C limited by the differential thermal expansion between the sintered binder and diamond table. Typical observations associated with such thermal failure of a PDC bit are loss of cutters, leaving empty circular recesses in the bit body, and ‘heat-checking’ on PDC cutter faces.
Alkenes are never observed as formation gases as they are not geological in origin; their presence is always as an artefact of the thermal breakdown of drilling fluid components described above, and therefore qualitatively proportional to the degree of thermal cracking taking place at bit – one product of so-called drill-bit-metamorphism – which in turn is proportional to the degree of bit wear generating thermal energy through friction. In short, alkenes can be used as a direct indicator of bit condition while drilling.
Standard surface logging equipment is used to extract a steady flow, at constant volume and temperature, of sampled gas from the return flow line. Traditionally, alkenes have been considered an unwanted contaminant of the formation-derived alkanes which are of interest for geological interpretation purposes. As ethene/ethane and propene/propane are of similar molecular weights, their peak response on standard field chromatograph cycles appear very closely, leading to potentially falsely elevated alkane readings unless the alkenes are properly and wholly removed from the gas sample stream by scrubbing filters prior to analysis.
However, when alkenes are of interest, a gas distribution manifold passes a separate raw sample gas stream to a second dedicated flame-ionisation detector (FID) chromatograph with modified columns that slow the mobile phase, thus allowing complete dissociation of alkenes from their respective alkane counterparts (as alkenes peak slightly earlier). A complete methane to propane cycle with full alkene separation is conducted every 240s with 5 ppm resolution, allowing for practically seamless realtime correlation with drilling parameters.
Figure 1. Real-time processing of alkene gases at rigsite from acquisition through measurement to monitoring.
This is part one of a two-part article. Part two will be available shortly.
Written by Matt Regan, GEOLOG International.
Read the article online at: https://www.oilfieldtechnology.com/drilling-and-production/12062019/qualifying-real-time-bit-wear-through-innovative-monitoring-of-alkenes--part-one/