6 Pneumatic Drill Fluids

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CHEVRON DRILLING FLUIDS MANUAL

SECTION VII PNEUMATIC DRILLING FLUIDS

Table of Contents

1.0 Introduction ..................................................................................... 2-7-2

2.0 Dry-Gas Drilling Fluids ............................................................... 2-7-32.1 Air ................................................................................ 2-7-42.2 Natural Gas ................................................................... 2-7-5

3.0 Mist Drilling Fluids ..................................................................... 2-7-6

4.0 Foam Drilling Fluids ................................................................... 2-7-64.1 Stiff Foam ..................................................................... 2-7-74.2 Stable Foam ................................................................. 2-7-8

5.0 Gasified (Aerated) Mud Drilling Fluids ......................................... 2-7-95.1 Air Application ............................................................... 2-7-95.2 Nitrogen Application .................................................... 2-7-11

6.0 Advantages/Disadvantages of Pneumatic Drilling Fluids ............. 2-7-13

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SECTION VII PNEUMATIC DRILLING FLUIDS

1.0 INTRODUCTION

Pneumatic drilling fluids are used to drill in areas where loss of circulation and low reservoir pressuresrestrict the use of conventional drilling fluids. Pneumatic fluids also find application to minimizeformation damage caused by: 1) invasion of mud filtrate and solid particulates into reservoir porespaces, 2) flushing of hydrocarbons, 3) hydration of clays within the reservoir, 4) emulsion blocking,or 5) formation of chemical precipitates within the reservoir. These damage problems are all causedby having a large overbalance of pressure resulting from a high hydrostatic pressure of the mudcolumn and from chemical incompatibility between the invading filtrate and the reservoir fluid. Causeof damage is eliminated, or at least diminished, by reducing the hydrostatic pressure of the drillingfluid column and by selecting a fluid that will not hydrate clays and will not form precipitates in thepore space.

Major equipment components which are required for pneumatic drilling, but not required forconventional mud drilling, are: gas/air compressor and boosters, a rotating head, chemical injectionpumps (for foaming agents and corrosion inhibitors), and foam generator units. In some cases otherequipment may be needed. Of the required components, the gas/air compressor is by far the mostimportant and costly. The entire drilling system design depends upon the capability and efficiencyof the compressors.

The ratio of final pressure to initial pressure controls the number of compression stages that isrequired. The number of stages of compression bears directly on the total drilling cost. Type andnumber of compressors required to handle each specific pneumatic drilling operation must be wellthought out in advance. Calculation of the compression ratio and ratio of discharge pressure tointake pressure is the first step in deciding on the number of compression stages. The compressionratio in a single stage should not exceed four because the temperature of the discharge air will betoo high. Cylinder temperatures above 300-400F will cause mechanical lubrication problems andmetal fatigue. Large capacity, high-efficiency, radiator-type coolers are required in order to reducethe air temperature between each stage of compression. Elevation and maximum air temperatureat the drillsite must be considered because compressor efficiency decreases with increasingtemperature and elevation.

Pneumatic drilling fluids may require one or more of three basic chemicals, but simple air drillingmay not need any of these:

Surfactants, as detergents or foaming agents Corrosion Inhibitors Drying Agents

Surfactants as Detergents and Foaming Agents - Anionic or nonionic surface active agents(surfactants) are injected into the inlet air stream when formation water is encountered. Thesefoaming agents also help clean the hole and keep the bit and drill string free of sticky solids.Surfactants prevent the cuttings from sticking together and from forming mud rings which can plugoff the annulus.

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Surfactants may also be added to the air stream or they may be added along with varying amountsof water to generate foam, as required by hole conditions. When water influx is minor, surfactantsmay be added in slugs down the drill pipe on connections. The surfactant (foaming agent) buildsa homogeneous mixture that has ample consistency to bring out the water and cuttings, therebycleaning the hole. The amounts of injection water and foaming agent used will vary according to thehole size, formation characteristics, available air, and quality and quantity of water/oil influx.

Corrosion Inhibitors - Corrosion during pneumatic drilling can be disastrous unless the drill stringis properly protected by corrosion inhibitors and scavengers. Oxygen, carbon dioxide and hydrogensulfide in the presence of water are extremely corrosive in pneumatic drilling. The rate of corrosioncan be minimized depending on the type of pneumatic fluid being used, by: 1) maintaining a highpH (10 or above) with NaOH or KOH if water is being injected, or 2) injecting corrosion inhibitors intothe gas or air. Sulfide scavengers such as zinc carbonate, zinc oxide or zinc chelate are used toreact with hydrogen sulfide to form inert zinc sulfide. Water-soluble and/or coating-type corrosioninhibitors (such as filming amines or phosphonates) should also be added to the fluid in order tofurther protect the steel components which are exposed to the circulating fluid.

Drying Agents - A wellbore which contains only a minor amount of water may be dried simply bydiscontinuing drilling and circulating air for a short time. Another method, which may prove to bemore economical, is to add slug treatments of drying agents such as CMC or silicate powders.These additives require the use of a dry chemical injector.

When deciding if a pneumatic drilling fluid is applicable, one must consider pore pressures, rocktypes, porosity and permeability, reservoir fluids, economics, and location. Types of pneumaticdrilling fluids discussed in this section are:

Dry Gas (air or natural gas) Mist Foam Gasified (Aerated) Mud

2.0 Dry Gas Drilling Fluids

Applications for dry-gas drilling are hard formations where water or oil flows are not likely to beencountered and areas where drill water is scarce. Dry-gas drilling (also called dusting) usescompressed air or natural gas to cool and to lubricate the bit, to remove the cuttings from aroundthe bit and to carry them to the surface. Dry gas is injected down the drill pipe while drilling andthe cuttings are returned to the surface as fine particles. The returns are vented away from the rigin order to minimize the noise and dust. Cuttings are caught by a specially designed screen at theend of the blooey line.

In dry-gas drilling operations, the bottomhole pressure consists of the weight of the gas column, plusthe annular pressure losses, plus the blooey-line pressure losses. The sum of these pressures willusually be far less than the formation pressure. Thus, the rate of penetration can be very rapid dueto the low hydrostatic pressure. Chip-hold-down is also eliminated, making cuttings release fromthe bottom of the hole much more efficient. Overall, dry-gas drilling offers economic advantages inhigh ROP and lower operational costs per foot of hole, compared to mud drilling.

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Dry-gas drilling operations require special and careful planning. Gas compressibility is a significantengineering consideration during both planning and drilling phases. Other equally importantconsiderations are annular velocity requirements and logging suite selections. Fluid annularvelocity, rather than fluid rheology, is the primary factor for cuttings transport when drilling with drygas. The annular velocity necessary to lift cuttings determines the volume of gas that must becirculated. These annular velocities are such that turbulent flow always exists. To lift 3/8" to 1/2"cuttings, as a general rule, an annular velocity of about 3000 ft/minute is required. Although mostair- or gas-drilled cuttings are quite small (dust particle size) when they reach the surface, they arelarger when they leave the bottom of the hole. The milling action of the drill string, impact with othercuttings, and regrinding of large particles at the bit are responsible for pulverizing them.

Logging is another factor to consider when drilling with dry gas. Wellbores containing no fluid otherthan air or gas can be surveyed only with devices that need no liquid to establish contact with theformation. The Induction Log is the only tool which can measure formation resistivities in such holes.The Gamma Ray Log can distinguish shales from non-shales. The Gamma-Gamma Density Logshows porosity even in gas-bearing zones where the Neutron Log indicates low apparent porosity.If both Gamma Ray and Gamma-Gamma Density Logs are run, the percent gas saturation may becomputed in clean formations. In flowing gas wells, the Temperature Log detects the producingzones by showing the cooling effects of the gas as it expands into the hole. Also, in multiple-zoneproduction, the Temperature Log indicates the relative volumes of gas coming from each zone. TheNoise Log may be used to record zones of liquid or gas influx as well as zones of severe loss. Arelative amplitude log is recorded and the noise may be monitored at the surface.

Water-bearing formations are the greatest limiting factor to air or gas drilling. Small amounts of watercan be tolerated by adding drying agents such as CMC to the dry gas to absorb the water. However,if the cuttings become too moist they will stick together to form mud rings which can block theannulus. If this occurs, loss of circulation, stuck pipe, or even a downhole fire may result.

2.1 Air - Air drilling is commonly used in areas where loss of circulation with liquid type muds isa major problem. Air is also used to drill hard, extremely low permeability rock or formations. Whendrilling gas-bearing formations the risk of downhole fires can be high. The chance of a downhole fire,when gas is present, is increased if the annulus becomes restricted, thus increasing the pressurebelow the obstruction. Mud rings can cause this type of problem. The standpipe pressure must becontinually monitored in order to detect and prevent an excess pressure build-up. Even an increasein pressure of about 15 psi can cause combustion to occur. Several downhole tools have beendesigned to help combat fire hazards. The Fire Float and Fire Stop are two of these tools. The FireFloat is installed above the bit as a near-bit protector. Under normal conditions it allows flow of airwhile drilling, but does not allow back flow of air. If the heat-sensitive ring is melted away by adownhole fire, a sleeve falls and stops air flow in either direction. A Fire Stop unit should be locatedat the top and midway in the drill collar assembly. It consists of a simple flap retained by a heat-sensitive zinc band. When the melt temperature of the zinc band is exceeded, the flap closes andair flow is halted. A quick rise in pressure at the surface is noted which alerts the crew to thelikelihood of a fire.

Volume and pressure requirements must be considered when selecting equipment for an air drillingprogram. Surface pressure is determined by the total system pressure losses. Atmospheric

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Table 1Hole Depth and Volume Required CFM

Hole StemSize Size 1000' 2000' 4000' 6000' 8000' 10,000' 12,000'

6-3/8 1840 1920 2090 2400 2520 2750 287012-1/4 5-1/2 2100 2150 2350 2640 2780 3000 3100

4-1/2 2260 2310 2520 2820 2930 3150 3230

6-3/8 1370 1430 1590 1850 1970 2180 229011 5-1/2 1580 1650 1820 2070 2160 2380 2500

4-1/2 1780 1810 1980 2250 2340 2530 2630

5-1/2 1180 1240 1400 1640 1730 1890 19709-7/8 5 1300 1360 1490 1710 1800 1990 2100

4-1/2 1350 1410 1540 1771 1850 2050 2150

5 990 1050 1180 1380 1480 1640 17409 4-1/2 1080 1140 1260 1470 1550 1720 1820

3-1/2 1130 1180 1300 1500 1580 1730 1790

5 930 970 1100 1320 1420 1570 16408-3/4 4-1/2 1000 1050 1160 1360 1440 1620 1730

3-1/2 1130 1180 1300 1500 1580 1730 1790

7-7/8 4-1/2 760 800 920 1080 1190 1330 14403-1/2 910 950 1040 1220 1300 1440 1500

7-3/8 3-1/2 760 790 880 1050 1120 1250 1330

6-3/4 3-1/2 610 630 730 890 980 1080 1140

6-1/4 3-1/2 500 520 610 750 800 930 10002-7/8 570 600 680 810 890 990 1070

4-3/4 2-7/8 300 340 400 480 560 630 6902-3/8 320 350 400 500 660 640 700

FOR GAS DRILLING INCREASE VOLUME 50%

pressure decreases with increasing elevation and temperature and increases with increasingrelative humidity. Equipment requirements for a location which is situated at a high elevation in ahot and dry climate are considerably different than requirements for one which is in a cold, humidclimate at sea level. Air requirements, based on an average annular velocity of 3000 ft/min, are listedin Table 1. In addition, as a rule of thumb for compressors there is a 3% loss in efficiency per 1000feet of elevation.

2.2 Natural Gas

Gas, rather than air, is used as the circulating medium when reservoirs contain appreciablequantities of gas. Air cannot be used because of the danger of downhole fires. The gas iscompressed in the same manner as air, but the return gas must either be flared or collected to beput into a pipe line. Recycling of the gas is not recommended because of the abrasive particles inthe used gas which would tend to damage the compressors. Fire and explosion hazards aroundthe rigsite, due to gas leaks, are a constant danger when drilling with gas.

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3.0 Mist Drilling Fluids

Misting may be used after drilling zones which produce more water than can adequately be absorbedby adding drying agents. In situations where the downhole influx of water is too much for dry-gasdrilling, but too little for mist drilling, it is possible to inject water at the surface to allow mist drilling.The quantity of water for mist drilling will depend on the hole size, type of formation, rate ofpenetration, etc. A high-volume water flow presents a different set of problems. The intrusion of largevolumes of water requires converting to a foam-type fluid and possibly other additives in order tosuccessfully remove the water.

In mist drilling, air lifts the cuttings, but water wets the hole. Mist drilling requires at least 30% moreair than with dry air or gas and higher injection pressures to adequately clean the hole. Increasedair volume is necessary due to the weight of the heavier fluid-wet column, the higher frictional lossescaused by the wet cuttings adhering to the drill string and the wall of the hole, and the higher slipvelocities of the larger wet cuttings.

Air drilling techniques are used in areas where water-sensitive shales exist. In most cases theseshales do not cause major problems if the air remains dry. However, these shales have a high affinityfor water and may become completely unstable if mist is used. These problems have beencontrolled, in some cases, by adding 1 to 5 weight % potassium chloride and/or PHPA (liquid) tothe injection water. Addition of the KCl reduces hydration and softening of shales and thus reduceshole enlargement. Small amounts (1 quart or less) of liquid PHPA can be added as a slug treatmentdown the drill pipe to act as a lubrication agent, reduce torque and drag and also to prevent hydrationand softening of shales. Injection of KCl-water into the air stream creates severe corrosion problems.Oxygen corrosion can be reduced by raising the pH of the water to the 10-11 range and by addinga corrosion inhibitor.

4.0 Foam Drilling

Foams can be classified as Foam, Stiff Foam and Stable Foam for discussion purposes. Theyare in many ways similar type drilling fluids.

Foam is differentiated from mist by the fact that foams may contain a blend of water, polymers,clays, surfactants and corrosion inhibitors. Transition from mist to foam may be necessary whendifficulties are encountered while using dry gas or mist. Some of these problems are hole erosion,inadequate hole cleaning, loss of returns and water flows. Foam structure provides rheology for liftingcuttings. Foam quality is the ratio of gas volume to total foam volume. This is the major factor whichaffects flow behavior. Apparent viscosity of the foam increases rapidly as the foam quality increases.Foam quality and foam stability will vary depending on the foaming agent used. The compositionof the injection water and the type of fluids entering the wellbore also affect foam properties. Somefoaming agents are not effective in salty or hard water. Foams are often damaged by presence ofoil. Selection of the right foaming agent can determine the success or failure of a foam drillingoperation.

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4.1 Stiff Foam

Stiff Foam is another type of foam classification. It is rheologically more like a mud than ordinaryform. It is a low-density drilling fluid used to drill poorly-consolidated formations in which hole-stabilizing materials can be included. The stronger foam supports larger cuttings compared tosimple foam. When stiff foam is used, the annular velocity can be from 100 to 200 ft/min for adequatehole cleaning. Consequently, compressor requirements are much less than for other types ofpneumatic drilling.

Stiff foam is formulated by premixing polymers in water in a mud pit. Sometimes smallconcentrations of bentonite are added. The mixture is transferred to the foam tank and the foamingagent is folded into this mixture with as little agitation as possible. Then, it is injected into the airstream. Enough air must be injected into the mixture to give 100 to 200 feet/minute annular velocitynear the surface. Air-to-mud ratios range from 100:1 to 300:1. The foam is very stiff, similar to theconsistency of aerosol shaving cream, in order to inhibit air breakout in the annulus. It cannot berecirculated and must be discarded at the surface by running it through a blow line to a sump orreserve pit. Stiff foam was introduced by the U.S. Atomic Energy Commission for drilling large-diameter holes in loosely consolidated formations. The original composition consisted of 10 to 15lb/bbl of bentonite, 0.2 to 0.5 lb/bbl of guar gum, 1 lb/bbl of soda ash, and 1% by volume foamingagent. Another relatively inexpensive, and somewhat more effective, formulation is: 12 lb/bbl ofbentonite, 1 lb/bbl of soda ash, 1/2 lb/bbl Hi-Vis CMC, and 1/2 to 1% by volume foaming agent. Thismixture, however, has the disadvantage of being relatively ineffective in the presence of salt wateror oil.

Table 2 lists typical additives, their function and concentration for formulating a stiff foam drilling fluid.

Table 2STIFF FOAM

ConcentrationAdditive lb/bbl Vol. % Function

Prehydrated Bentonite 10 - 15 Builds Foam Structure

Carboxymethylcellulose (CMC) 0.5 Foam StabilizerDrying Agent

Guar Gum 0.2 - 0.5 Foam Stabilizer

Soda Ash 0.5 - 1.0 Calcium Treating AgentCaustic Soda/

Caustic Potash 0.55 - 0.5 Corrosion Protection

Foaming Agent 1% Stabilizes Air in LiquidPotassium Chloride 3 - 5 % Shale Stabilizer

Filming Amine 0.5% Corrosion Protection

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4.2 Stable Foam

The difference between Stiff Foam and Stable Foam is the method used to prepare the foam. StableFoam was developed by Chevron as a completion and workover fluid. Its distinguishingcharacteristic is that it is preformed on the surface in a foam generating unit. Then, it is injectedinto the drill pipe. The equipment required for making stable foam is: 1) an air compressor, 2) tanksfor blending water, detergent and additives, 3) detergent solution pump, and 4) the foam generatorand injection manifold.

Stable Foam consists of a detergent, fresh water and gas. Other additives such as viscosifiers,salts, or corrosion inhibitors may be included in the mixture. To be used effectively as a circulatingmedium, stable foam must be preformed. This means it is made before it encounters any solidsand liquids from the wellbore. The foam is circulated only once. Foam systems have characteristicswhich make them stable and resistant to wellbore contaminants. Impurities introduced during foamgeneration can destabilize the foam.

Foams can be prepared with densities as low as two pounds/cubic foot by carefully controllingselection and mixing of components. Viscosity can be varied so that high lifting capacities resultwhen annular velocities equal or exceed 300 feet/minute. (Bottomhole pressure measurementshave indicated actual pressures of 15 psi at 1,000 feet and 50 psi at 2,900 feet while circulating stablefoam.)

Stable foam should have a gas-to-liquid volume ratio in the range of 3 to 50 ft3/gal, depending ondownhole requirements. The water-detergent solution which is mixed with gas to form stable foamcan be prepared using a wide range of organic foaming agents (0.1-1 percent by volume). Aschematic diagram of a stable foam unit is shown in Figure 1.

Figure 1Stable Foam Unit

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Table 3 lists typical components, their function and concentration for formulating a preformed stablefoam drilling fluid.

Table 3STABLE FOAM

ConcentrationAdditive lb/bbl Vol. % FunctionPrehydrated Bentonite 10 - 15 Foam Stabilizer

Polyanionic Cellulose 0.5 Filtration Agent

Drying AgentSodium Polyacrylate 1 Filtration Control

Foaming Surfactant 1% Foaming Agent

Potassium Chloride 3 - 5 % Borehole StabilizerXC Polymer 0.25 - 1 Foam Stabilizer

Filming Amine 0.5% Corrosion Protection

Lime 0.25 - 0.5 Corrosion Protection

5.0 Gasified (Aerated) Mud Drilling Fluids

Air or gas can be used to reduce mud density and the resulting hydrostatic pressure of any mud.Gasified mud may be used for a drilling fluid when downhole drilling conditions prohibit the use ofdry gas, mist or foams. It may also be used when drilling into low pressure reservoirs. Returns areoften lost at a shallow or medium depth while an overpressured zone is being drilled at a greaterdepth. Gasification can be beneficial as a way to reduce the hydrostatic pressure of shallow zoneswhile maintaining adequate hydrostatic pressure at the deeper zone. Two of the most commongases to reduce the hydrostatic pressure of the mud column are air and nitrogen. Both of theseapplications will be briefly discussed in this section.

5.1 Air Application

Due to its compressibility, air in an aerated mud is compressed to very small bubbles as it travelsdown the drill pipe and through the bit. As the air in the mud travels up the annulus toward the surface,the air bubbles slowly expand due to the decreasing hydrostatic pressures, which in turn increasethe air-volume to mud-volume ratio in the upper portion of the annulus. The rate of air bubbleexpansion increases according to the general gas law as the aerated mud approaches the surface.This increase of air-volume to mud-volume ratio not only decreases the downhole hydrostaticpressure, but increases the annular velocity of the aerated mud as it approaches the surface. Thenomograph in Figure 2 may be used to estimate air requirements for reducing density of a water mudby aeration.

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Figure 2Air Requirements for Reducing Density of water muds

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A de-aerator, such as a mud-gas separator, must be used to control high velocity and possiblesurging of the returning mud before it goes to the shale shaker. This device will prevent surface mudlosses due to surging and splashing as well as remove a large portion of the air from the mud. Theseparator should have an overflow line going to the shaker in case of excessive fluid flow. The balanceof the air will be removed by the degasser prior to reaching the mud pumps.

Control of the mud properties is extremely important when drilling with aerated mud. The density,solids content, gel strengths, and plastic viscosity must all be controlled at low and constant values.The yield point will depend on the type of fluid being used, but should be in a proper range with respectto the plastic viscosity. Yield point control is required in order to allow the air to be removed whenit reaches the surface. Injection pressures will remain low if hydrostatic pressure and systempressure losses are maintained at low values. As well depth increases, controlling hydrostatic andsystem pressure losses becomes more important in order to avoid surpassing the capabilities ofthe air equipment. Maintaining a pH above 10 will assist in corrosion control; however, higher pHcould cause polymer precipitation or cuttings dispersion depending on the type of mud being used.

Some common fluids used in aerated drilling are low-solids, non-dispersed muds and salt muds.Low-solids, non-dispersed (LSND) muds are especially good as aerated drilling muds because theyoffer shear thinning properties which give low circulating pressures. Their major drawback is atendency to disperse cuttings at high pH, so care must be exercised when selecting additives inorder to prevent dispersion.

Potassium chloride muds are very successful in solving unstable shale problems in air-liquidcirculating systems. Potassium hydroxide should be used for pH control. Fluid loss control maybe obtained by using polyanionic cellulose. The major disadvantage of salt muds is higher corrosionrate compared to freshwater muds. Removal of entrained air or gas from a salt mud can be difficult.

5.2 Nitrogen Application

Nitrogen can be used to solve loss of circulation in areas which have an abnormally low pressuregradient. Nitrogen can be injected into the mud system at the standpipe in order to accuratelycontrol annular hydrostatic pressures and thus regain mud returns.

Nitrogen has advantages over other aerated systems because pressure, volume, and temperatureof the gas from a tank of liquid N2 can be better controlled and temperature is lower than air froma compressor. Temperature is a major factor to be considered while working with an aerated system.If nitrogen is put into the drill string at a cool temperature, it will expand as the temperature increases.The amount of expansion, and thus the effective lowering of mud density will be greater. The effectivemud density at various depths is shown in Table 4. Tables available from nitrogen suppliers aredesigned for a geothermal gradient of 1.6F per 100 feet of depth.

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Table 4Effective Mud Density at Various Depths Using Nitrogen

Mud

Density Nitrogen

lb/ gal scf/bbl Depth, Feet

1000 2000 3000 4000 5000 6000 7000 8000 9000

9.0 10 7.72 8.16 8.36 8.48 8.56 8.61 8.65 8.68 8.71

9.0 20 6.62 7.19 7.63 7.88 8.05 8.17 8.26 8.33 8.39

9.0 50 3.04 4.58 5.53 6.13 6.55 6.85 7.08 7.26 7.41

10.0 10 8.69 9.15 9.35 9.47 9.55 9.60 9.64 8.68 9.70

10.0 20 7.16 8.15 8.60 8.86 9.03 9.16 9.25 9.32 7.42

10.0 50 3.67 5.41 6.43 7.07 7.50 7.81 8.04 8.23 8.38

11.0 10 9.66 10.13 10.34 10.46 10.54 10.60 10.64 10.67 10.70

11.0 20 8.08 9.11 9.85 9.94 10.02 10.14 10.24 10.31 10.37

11.0 50 4.29 6.25 7.33 7.99 8.44 8.76 9.00 9.19 9.35

Nitrogen is pumped at the required rate directly into the standpipe until a joint of pipe isdrilled down. In order to prevent the mud in the drill pipe from blowing back duringconnections, a mud cap (a column of liquid mud) equal to approximately 1000 ft can bepumped prior to breaking the connection or a string float can be used. The connection canthen be made before the nitrogen can come back up through the mud. A string float mayalso be used for this purpose.

Due to the compressibility of nitrogen, the pressure gradient of the mud inside the drillpipewhile circulating is not greatly reduced. For example, a mud pressure gradient of 0.467 psi/ft, with a pump pressure of 2,000 psi, will only be reduced to 0.440 psi/ft with the additionof 50 standard cubic feet (scf) of nitrogen per barrel. Only after passing through the bit jetsand coming up the annulus will the nitrogen bubbles expand and lower the pressure gradientdrastically. This can be seen in Table 4 where the density of a 9.0 lb/gal mud is reducedfrom 7.41 lb/gal at 9,000 ft to 6.55 lb/gal at 5,000 ft as the pressure is decreased in theannulus.

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6.0 Advantages/Disadvantages of Air Drilling Fluids

There are a number of significant advantages for using air as a drilling fluid. Table 5 listssome of these advantages as well as some of the disadvantages.

Table 5DRY GAS VERSUS LIQUID MUDS

Advantages Disadvantages

Excellent ROP in dry competent formations. Will not tolerate water.

Low-cost fluid. Dust and noise problems on location.

Longer bit life. Excessive erosion near top of hole whereexpansion results in high annular velocity.

Minimum damage to water-sensitive pay . May cause downhole fire when hydro-zones. carbons are encountered. (Air Drilling)

Little or no fluids disposal problems. Hole cleaning success difficult to determine due to inability to adequatelyquantify cuttings removal.

Hydrocarbon identification immediate and Requires experienced rig personnel.continuous.

Lost circulation eliminated. Special (rental) equipment required.Limited information on reservoir char-acteristics because cuttings are pulverized.

Disposal of waste gas can be a hazard.(Gas Drilling)

Table 6 compares Mist and Dry Gas drilling fluids. Mist offers nearly the same advantages as drygas versus liquid muds with one exception: it can handle a sizable water volume compared to drygas drilling. The Table also lists some of the disadvantages of using mist versus dry gas.

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Table 6MIST VERSUS DRY GAS


Same as dry gas except chemical Requires more air volume.additive cost increases.

Handles sizeable water influx. Corrosive.

More hole enlargement due to water-shaleinteraction.

Stiff foam exhibits additional advantages over dry gas or mist drilling fluids. Table 7 lists some ofthese advantages as well as some of the disadvantages.

Table 7FOAM VERSUS MIST OR DRY GAS


Wall building capability Increased mud and chemical costs.

Loses solids carrying capability when encountering oil, salt water or calcium ioncontamination.

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Table 8STABLE FOAM VERSUS STIFF FOAM


Lost circulation and formation damage High surfactant costs.eliminated.

Low compression requirements. Additive ratios critical.

Good thermal stability. Specialized equipment required for measur-ing and regulating liquid and air proportionsand quantities.

Compatible with oil, salt water and calcium and most formation contaminants.

Can safely absorb considerable volume ofgas into aqueous foam rendering it non-flammable until sumped.

Less hole washout in unconsolidatedformations while drilling.

6 Pneumatic Drill Fluids

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