Enabling real-time drilling fluid diagnostics with % Oil, % Water, % LGS & % HGS that allows the opportunity to optimize the drilling fluids engineering process. By optimizing the dilution costs, reducing drilling waste and increasing solids control efficiency we can reduce overall costs and improve both environmental and safety overall. With the primary well control barrier better managed, overall reduction NPT and ILT is achieved. Incremental approach to implementing a SiCon system installation on various locations can include active tank/mud pump suction, return line at the shakers as well as the centrifuge suction and effluent lines while delivering cost benefits at every stage. SiCon will help Engineers connect the dots between drilling fluids dilution, solids control efficiency and waste management.
Two sensors, one installed at the Return Flow Line and the other at the Bell Nipple, are combined by an algorithm to produce one Flow Out reading that delivers unprecedented levels of accuracy and precision. Whether using the AFH% to produce Flow Out % (Flow Height) or the more advanced AFH-GPM to produce volumetric Flow Out GPM, the system wide sensitivity, crucial for seeing micro-kicks/losses and clearly defining flowback signatures is unprecedented. We have at least one case where through flowback signatures allowed the operator to mitigate a possible wellbore instability issue by seeing a consistent signature depicting transition from normal flowback to that of a ballooning/breathing wellbore. Detection of warning/anomaly was later on proven > 3 hours ahead as compared with the traditional flow paddle sensor.
Such a powerful sensor assembly that delivers full rheological profile
Obtaining reliable density measurements from active pits of drilling rigs remained elusive even after most providers shifted to submersible electronic diaphragms from traditional hydraulic capillaries. Especially for drilling circulation where old mud meets new mud nearly continuously, errors caused by tank agitation of up to 0.5 ppg makes the best “single density” sensors fall short. Many have opted to pump out mud sample stream through a standard sensor (e.g. Coriolis), not realizing that the mud sample remains affected by agitation anyway thus readings remain questionable.
Real mud density in a tank is measured within the confines of the tank, represented by the entirety of the tank's content and condition. To isolate and remove agitation effects, a sensor array (i.e., multiple measurements) with smart averaging and compensation algorithm is necessary. This is precisely what TPA was designed for.
For non-MPD mud circulation in a drilling operation, the last stage where outflow drilling fluid retains its gas and cuttings contents, both consistent indicators of wellbore safety and efficiency, is before the return flow line. With the technical challenges figured out by Absmart regarding compensation algorithms for moving fluid, meniscus, sharp turn into the flow line and sensor specifications, density measurement after the BOP and before the flow line delivers unmatched density data that in turn provides crucial insight into formation gas and drilled cuttings.
Density reading from the ADS, taken together with Flow reading from AFH+RFM, allows clear distinction between a benign gas peak (e.g., connection gas) and a dangerous gas kick, minutes ahead of gas detectors.
Density reading from the ADS, taken together with inflow Density reading from TPA, allows unprecedented clarity in characterizing Hole Cleaning effectiveness during drilling.
Many drilling instrumentation companies offer EDR packages but only a few provide EDR designed with seamless AD upgrade option. Besides creating the fastest and smoothest wellbores with its electromechical link feedback, our AD is likely the most cost-effective option available.
From a lean EDR scope appropriate for a workover rig to a complete EDR+AD system for a full size rig to modernize and deliver better directional control, decreased anomalies, prolonged bit life and BHA, our scalable system will likely meet your requirements.
Constant Volume Trap (CVT) redefined. While retaining strict adherence to Texaco-GRI QGM design supported by decades of research and field track record, a single VFD-controlled motor maintains exact mud sample volume refresh rate and agitation rates regardless of variation in the mud density and rig power. Further reduction in maintenance downtime is achieved through a quick-connect sample filter cannister, with a screen area 4x the area of typical CVT sample probe. An optional and completely independent heater module is a cost-effective add-on when handling excessive cool downs of ultradeepwater risers.
The PFI offers the most viable path for CVT-QGM to become the industry standard gas extraction device.
The O&G industry is now into its third decade since non-FID hydrocarbon gas detectors have been introduced and at one point with their “lower operational cost” features such as requiring neither hydrogen nor compressed air, have nearly been considered the de facto standard, until recently. With faster drilling and shale wells, the 10x greater precision and much lower detection limit offered by the FID, coupled with improvements in cost and safety of maintaining hydrogen source with a low-power, safe low-flow hydrogen generator, geologists and reservoir engineers realize that the compromises using low sensitivity Infrared, microTCDs, and catalytic combustible gas analyzers, are no longer acceptable.
With FID fast becoming the preferred type of gas analyzer for well drilling, a closer look at various FID features (e.g., true cycle time, ease of use, cost), will lead most to choosing Absmart FID systems.
With TSG's field adjustable diaphragm positions, one type of multi-parameter sensor (Density, Temperature, Level, Volume) covers tanks as shallow as 18 inches (e.g., modern possum bellies), gumbo catchers, return flow dividers, sluice boxes, land rig 5-ft pits, to offshore tanks as 25-ft deep. 1-inch diaphragms make TSG an attractive lower cost-of-ownership alternative to Coriolis sensors for 'pumped-in' density applications (e.g., inline to CVT system).
Moreover, many are unaware that it is erroneous to treat SG as merely a derivation from PPG by a constant multiplier. Properly calculated (i.e., SG = fluid temperature-normalized densities ratio) it makes SG a true indicator of any mass/volume density change, which improves mud control accuracy by as much as 5%.
After 25 years of full-pipe sensor use forcing costly major rerouting of return flow lines of all rig types, only a handful globally can be found, of which many went back to relying solely on traditional flow height (%) sensors. The Rolling Flow Meterintroduced 1990s had the right intention of enabling true quantification of inflow-outflow delta with volumetric flow at the return flow line, but fell short of widespread acceptance because of unreliable potentiometric analog sensors, insensitivity to low flow and small changes, and insufficient compensations.
Abs RFM retains the cost-effective partially-filled pipe approach for the return flow line, but with new technology implementations such as digital encoder and proximity sensors and dedicated flow computer with buoyancy compensations for low flow changes.
Introduced back in 2004 as the world’s first, with hundreds sold to date and MTBF > 5 years, the FLE remains to be the most cost-effective step in upgrading return flow indicators that are analog-sensing based, including potentiometric, resistive and magnetic field. Multitude of field data showing 6x reduction in signal jitter with digital sensing is compelling.
Today, amongst many encoder-based versions, with our volume-manufacturing advantage and track record, FLE continues to be a strong price and reliability choice.
Copyright © 2018 Absmart USA LLC