During a gas kick in a Wyoming wildcat well, blowout prevention procedures were complicated by equipment failure and the presence of H2S. This paper describes the use of a specially prepared magnetic iron oxide to remove the H2S chemically from drilling fluids. This mud treatment protected the drillpipe from corrosion and prevented the release of toxic gases, allowing the well to be killed successfully. Introduction Drilling a well in an area where gas containing hydrogen sulfide (H2S) can escape poses grave risks. The complications of dealing with H2S at the surface, as indicated by Goolsby, emphasize the importance of good blowout prevention procedures and of precipitating out any H2S entering the wellbore. The combination of treating the drilling fluid with NaOH to absorb H2S and with zinc compounds to precipitate H2S has proven successful. The combined treatment has disadvantages, particularly the relatively large quantities of treating particularly the relatively large quantities of treating chemicals required and the harmful effects on drilling fluid properties, especially those of low-solids, nondispersed polymer muds. These disadvantages encouraged us to search for an alternative sulfide scavenger. Reactions H2S reacts with water and is extremely destructive to steel. Typically, in basic drilling fluids, H2S is neutralized by this reaction: H2S + NaOH NaHS + H2O This reaction theoretically requires 1.174 kg NaOH to neutralize each kilogram of H2S. The reaction is essentially complete at pH higher than 9, but lowering the pH below 9 would allow free H2S to escape.Zinc carbonate reacts with sulfide ions in solution to form insoluble zinc sulfide: ZnCO3 + NaHS ZnS + NaHCO3 This reaction theoretically requires 3.679 kg zinc carbonate to precipitate each kilogram of H2S. Zinc sulfide (wurtzite or sphalerite) has a specific gravity of about 4.0. Commercial zinc compounds are either basic zinc carbonate, which contains up to 50 wt% zinc, requiring 3.8 kg material to precipitate each kilogram of H2S, or organic zinc chelates, which may require 10 kg or more for each kilogram of H2S. Precipitated zinc sulfide has an extremely low solubility in water and does not pose any hazard in neutral or basic drilling fluid, but zinc sulfide is soluble in dilute acids. Muds containing zinc sulfide could release H2S at any time if the mud should become acidic (Table 1).While searching for a more effective material, we noted that ferrous hydroxide reacts with H2S under the fight conditions to form iron pyrite, which is insoluble even in concentrated hydrochloric acid. The proposed reaction is Fe(OH)2 + 2 H2S FeS2 + 2 H2O + H2 This reaction requires 1.32 kg ferrous hydroxide to precipitate each kilogram of H2S. This reaction appeared precipitate each kilogram of H2S. This reaction appeared to be almost three times as effective on a weight basis as zinc compounds are in removing H2S from solution in mud. The precipitate is a naturally occurring, stable compound that would not have adverse environmental effects. However, ferrous hydroxide is not readily available nor very soluble in drilling fluids and it reacts slowly with H2S. JPT P. 797

Summary The development of rotary rock bits with jet nozzles required means of estimating pressure losses in the drilling fluid flowing throughout the well being drilled and through the associated equipment. The initial tabulations were based on Newtonian fluids. Subsequent authors developed descriptions of drilling fluids based on Bingham or power law non-Newtonian fluid models. Because optimum-hydraulics theories dictate that hydraulic horsepower, impact, or impact force must be maximized, we made the difficult decision to determine these pressure losses by actual tests. A total of 119 water-base drilling fluids were pumped through capillary tubes up to 2 in, in diameter and through six standard sizes of drillpipe tool joint combinations. Drilling fluids were flowed through jet bit nozzles and were flowed up two annulus-size combinations as well as an annulus with hole enlargements. The annular tests included cuttings, which aided in determining flow patterns. This paper includes development of friction factors and empirical corrections for current theories to model flow of highly non-Newtonian fluids more reasonably. Procedures and equations arc offered to help estimate pressure losses in a drilling operation, even with very limited fluid property information typical of our industry. Introduction Field tests of flocculants and other polymers added to water or clay water drilling fluids resulted in lower pump pressures and higher pump speeds than predicted with available tables. In some cases, these pressure reductions were dramatic and resulted in loss of rig time inspecting for equipment failure. Field pressure measurements showed that the pressure losses for actual muds were significantly different from those calculated by available methods. A laboratory test facility was constructed to measure the exact pressure losses for various types of drilling fluids in actual drillpipes and annuli. The initial concept was to develop more comprehensive tables for various types of muds in the range of pipes used. After initial tests it became apparent that the number of tables required would make their use unattractive. Because this work was to assist field personnel in calculating pressure losses so that hydraulics could be optimized, it had to be based on flow property measurements available in the field. The best available field data are often the Fann plastic-viscosity and yield point measurements based on the 600- and 300-rpm readings. Dodge and Metzner indicate that the powerlaw fluid model can be used to describe the flow of drilling fluid in pipes; therefore, these fluids were treated as power-law fluids with suitable corrections to be applied where required. Equipment Flow properties and pressure drop in pipes were measured by pumping the test fluids through 10 pipes ranging in ID from 0.187 to 3.826 in. and in annuli from 5.044 × 2.5 to 12.715 × 5.0 in. Nominal 20 in. welded pipe and six types of drillpipe were manifolded into the full-scale test system. This system included a 20-bbl mud tank, a 100-hp electrically driven centrifugal pump, and automatic diaphragm valves for flow and bypass controlled by the flowmeter. Flow rates were measured by )- to 500- and 0- to 50-gal/min flowmeters that demonstrated better than 0.25% full-scale accuracy. Differential pressure along the test sections was measured with 0- to 100-psi, 0- to 400-in. water, 0- to 100-in, water, and 0- to 20-in. water differential-pressure cells. An automatic continuous flow of city water from the cell to the pressure taps was maintained at a rate of about 20 cm /min to prevent mud from entering the test lines. JPT P. 1414^

Drilling costs are a significant portion of exploration and production budgets.

No abstract

The first-year goal of this study was to better understand the underlying physics affecting the separation capability of TCAP in order to provide a strong technical basis for design of a scaled up mega-TCAP, of interest for fusion and other potential applications. Assessing mass transfer factors, researchers performed an extensive review and evaluation of prior theoretical work, mathematical models, and experiments on chromatographic separation. This effort resulted in the discovery of a previously unidentified factor impacting TCAP column scale-up. A model derived by J. Calvin Giddings indicates that the combination of coiling a packed column and increasing the column tube radius will decrease column separative performance. FY2019 Objectives Understand the fundamental physics of the efficiency losses previously noted during the 2004 HT-TCAP scale up and devise means to overcome them through the following: • Determine the factors affecting and affected by TCAP gas mass transfer • Determine the factors affecting and affected by TCAP heat transfer.