Gasbase Drilling Fluids Technology

In Chapter 1, principal component formed the basis for classifying three different types of drilling fluids. Of these, gas-base drilling fluids include those in which air or other gas is the continuous phase (e.g. dry gas, mist) and those in which gas is the discontinuous, or internal, phase (e.g. foam, stiff foam). The term reduced-pressure drilling fluid can be applied to all of these systems because they are used to reduce the pressure gradient of the drilling fluid to less than that exerted by a column of water. The original purpose for using gas-base fluids was to avoid loss of water, and the resulting damage to productive zones. A secondary benefit that became of major importance in hard rock areas was a faster drilling rate.

Dry Gas Drilling

Brantly2 5 5 cites a patent issued to P. Sweeney in 1866 as the earliest record he found suggesting use of compressed air to remove cuttings from a drilled hole, although air had probably been used by earlier drillers. Pressure drilling with a control head, which allows control of gas and oil flow while drilling the productive zone, was employed in the early 1920s in Mexico. The practice spread to other areas.

The first recorded injection of gas occurred in September 1932.236 To keep water out of producing zone at 8,800 ft (2,680 m) in the Big Lake Field in Reagan County, Texas, gas at a volume ratio of 143 to 1 was metered into the circulating water. Shortly thereafter, the closed-fluid circulating system was employed for drilling in the Fitts Pool in Pontotoc County, Oklahoma, and productivity was greatly improved compared to that of wells drilled with mud.-J1 Similar gas-injection practices were followed in California for drilling subnormal-pressure sands.338

Around 1950, small rigs drilling shot-holes for seismic exploration began to use compressed air in areas where water was scarce (West Texas) or where temperatures were low (Canada).23S In May 1951, El Paso Natural Gas Co. in the San Juan Basin, New Mexico, began drilling with gas to avoid loss of circulation in the Mesa Verde section from 4,000-5,000 ft (1,200-1,500 m). Rate of penetration and footage per bit increased greatly. More important, well clean-up was facilitated, and productivity was much higher than when mud was used.240 Economical development of the extensive San Juan Basin gas fields (1951-53) was made possible by use of gas as the drilling fluid.

The use of natural gas in successfully avoiding both loss of circulation and the accompanying damage to the producing formation led to the introduction of air drilling in Martin County. Texas, in June 1951.241 Because natural gas was unavailable, compressed air was used. To supply the air, nine small two-stage compressors and three single-stage boosters were assembled as shown in Figure 2-10. The volume of air supplied was not sufficient to clean the hole, however, until circulation was reversed. Air was used in drilling from 6,620 to 7,542 ft (2,018-2,300 m). Unless liquid was produced in sufficient amount to show a spray at the surface while drilling with reverse circulation, fine cuttings would adhere to the inner wall of the drill pipe. This observation led to the practice of injecting water with air whenever cuttings contained just enough moisture to be sticky.

In the next few years, attempts were made in many areas to employ air as the drilling fluid for increased penetration rate and footage per bit. Where water-bearing formations did not interfere, both air and natural gas showed outstanding advantages, wherever one or more of the following conditions

Figure 2-10. Composite view of the 9 Iwo-stage and 3 one-stage compressors supplying air lor this unusual drilling project. The compressor manifold and cooling system may be seen in the illustration. (From Berry:m World Oil.)

existed: loss of circulation; susceptiblity of producing formation to water or water-base mud damage; high expense or unavailability of water or mud '1 Observation showed that significantly faster rate of penetration and more feet of hole per bit were typical. As the method was tried in different areas, both practical limitations and advantages were recognized.243,244-245

R.R. Angel246 calculated air requirements for typical hole and pipe sizes based on three assumptions. First, the annular velocity is 3,000 ft/min (15 m/sec). Second, a homogeneous mixture of air and cuttings with the flow properties of a perfect gas is formed. Third, the geothermal gradient is applicable as the temperature of the gas. The expanded tables247 were published in 1958.

Problems with Water-Bearing Zones

Early in the use of air as a drilling fluid, water-bearing formations were found to be a major limiting factor. Often, when water-saturated formations were drilled, the wetted cuttings stuck together and were not carried from the hole by the air stream. When the wet cuttings filled the annulus, a mud ring was formed: the air flow was shut off and the drill pipe was stuck. Yet, when water was injected with air to prevent mud ring formation, some formations became unstable.

Several methods of shutting off water were tried, including (1) forcing a liquid mixture of two polymers into the water-bearing formation, to form a stiff gel;248 (2) introducing a solution of aluminum sulfate followed by ammonia gas to form a precipitate;249 (3) injecting silicon tetraflouride gas into the water to produce a solid plug;250 and (4) injecting a liquid, a titanium ester called "Tetrakis," to form a precipitate with the water present. ' 5 Certain methods had some success;2 52 however, the problems of placement and the likelihood of drilling into other water-bearing zones rarely justified the expense. Wetting and balling of cuttings can be diminished by introducing zinc or calcium stearate into the air stream.2 53


When the quantity of water entering the hole from the water-bearing formation exceeded about 2 bbl/hr (0.3 m3/hr), the water could be brought out of the hole as a foam by injecting a dilute solution of a suitable foaming agent into the air stream. Foam effectively removed cuttings at lower annular velocities than was possible with air253 and as much as 500 bbl/hr (80 m3/hr> of water could be brought from the hole. With such quantities of water coming into the hole, however, the time spent unloading the hole after a trip was prolonged; the cost of foaming agent became excessive, and water disposal became a problem.245 Further experience with foam led to more consistent operating practices, and the advantages and limitations in its use became more clearly defined.254 ■-'51 -<ft

Numerous foaming agents were on the market and several test methods had been used.253'25'1 ■:<7-25S The need for standardization of methods was evident. The API Mid Continent District Committee for Air and Gas Drilling recommended test procedures which involved brine, fresh water, and fresh and salt water containing oil.250 API Recommended Practice 46 was issued in Nov. 1966.260

Aerated Mud

Another approach toward avoiding loss of circulation through reduced-pressure drilling was used by Phillips Petroleum Co. in Emory County, Utah, in May 1953.261 In the initial test, air from a small compressor was injected into the mud stream between two mud pumps connected in series. Although circulation was maintained while drilling to 3,300 ft (1,000 m), the method of air injection was inefficient and, in subsequent studies in West Texas, air from a three-stage compressor was injected directly into the standpipe.-"- A special check valve placed in the drill string one joint below the kelly avoided the problem of mud spray when making connections.

Drill pipe corrosion was severe in early tests of aerated mud, but by maintaining the pH of the mud above 10, corrosion was reduced. Maintaining saturation with lime minimized corrosion while drilling competent formations with water.

While using the aerated mud system, water influx or mud loss often could be controlled by adjusting the volume of injected air. As the density of the mixture increased, however, the drilling rate decreased, and loss of circulation again became a problem.

Aeration of mud downhole by injecting air into the annulus between the casing and the drill pipe was the method used to avoid lost circulation in the Upper Valley field in Utah.263 Earlier wells had shown the static water level after loss of circulation to be about 1,000 ft (300 m), while depth of the major loss was about 3,000 ft (900 m). Parasitic tubing (tubing attached to the outside of the casing), was run to the calculated point of injection. Substantial savings in well costs resulted from this method of reduced-pressure drilling.

The introduction of dual drill strings and dual swivels supplied another method of reduced pressure drilling.264 -65 In this system, air is forced down either the inside or the annulus of the dual drill string to the calculated depth, where it is injected into the outer annulus. The pipe annulus that does not convey air carries mud to the bit. As with the parasitic tubing method, the air mud mixture exists only in the annulus above the injection point (See Figure 2-11).

Dual Swivel

Mud in

Air in ^ Rotating Head


Mud Returns

5-inch Concentric Drill Pipe

Jet Sub

41/2-inch Conventional Drill Pipe

Drill Collars

Mud in

Dual Swivel

5-inch Concentric Drill Pipe

Jet Sub

41/2-inch Conventional Drill Pipe

Drill Collars

Static Fluid Level


Figure 2-11. Concentric drill pipe/air lift method for reduced-pressure drilling. (From Binkley.264 Courtesy of API.)

Static Fluid Level


Figure 2-11. Concentric drill pipe/air lift method for reduced-pressure drilling. (From Binkley.264 Courtesy of API.)

Gel Foam or Stiff Foam

The introduction of gel foam, or stiff foam, was a notable advance in the technique of foam drilling. This form of reduced-pressure drilling contributed largely to the solution of lost circulation and hole cleaning problems at the U.S. Atomic Energy Commission's Nevada Test Site. After efforts to establish circulation by the usual methods had failed, air and foam were tried in 1962, but removal of cuttings from the large-diameter holes (64 inches, 163 cm) was extremely troublesome. In 1963, a drilling fluid was developed that, along with some changes in drilling practices, greatly reduced costs of the big holes.266,267 268 At a central mixing plant, a slurry was prepared consisting of (by weight) 98% water; 0.3% soda ash; 3.5% bentonite, and 0.17% guar gum. At the drill site, 1% by volume of foaming agent was added to the slurry. The injection rates of air and slurry were carefully controlled to maintain returns of a foam having a consistency similar to shaving cream With the gel foam, rising velocities as low as 100 ft per min (0.5 m/sec) were adequate in drilling holes 64 inches (163 cm) in diameter. Hole stability in caving zones was improved by the gel foam. This feature of gel foam has proven especially valuable. Other polymers have been substituted for guar gum, and have also replaced bentonite in some applications.

Preformed Stable Foam

A further contribution to reduced-pressure drilling was the development of a foam generating unit by Standard Oil Co. of California, around 1965. In this device, the metered gaseous and liquid phases are mixed at the surface, and the preformed foam is introduced into the drill pipe.269 The diagram, Figure 2-12, illustrates the equipment employed. The compositions of the foaming agent and of the polymer (or polymers) can be selected to satisfy the

Figure 2-12. Preformed stable foam flow diagram. (From Anderson.271 Courtesy of AAODC.)

conditions for application of the foam. For example, the composition needud for a well cleanout involving some oil and brine might differ from that employed in drilling shale. Similarly, composition of the gas might depend on availability, convenience, and cost of supply.

Optimum application of the technique requires careful planning. A mathematical model was designed and a computer program was formulated to aid in the selection of facilities for any given application.2"0 In a survey of preformed foam applications,27' several publications dealing with numerous uses in worldwide applications were cited.

Flow Properties of Foam

Measurement of the flow properties of foam in oil field applications began to receive attention in connection with the foam-drive process for increasing recovery of oil. In the early 1960s, viscosity of foam was measured in a modified Fann viscometer.2"2 Later, measurements were made in small diameter tubes.2The major factor affecting flow behavior was found to be foam quality, the ratio of gas volume to total foam volume at a specified temperature and pressure. Apparent viscosity increased rapidly as foam quality increased from about 0.85 to 0.96, the limit of foam stability at the mist condition. Based on the behavior of foam as a Bingham plastic, charts were prepared for common drill pipe and hole sizes to allow estimations of air-volume and water-volume rates, and injection pressures, that minimize hydraulic horse-power.276

Composition of foam at any temperature and pressure can be expressed also as liquid volume fraction (e.g., LVF= 1 —quality). The particle-lifting ability of foam increases as liquid volume fraction decreases. From data obtained in pilot-scale experiments, Beyer, Millhone and Foote27" derived equations for the flow of foam in circular pipes. Two velocity components were involved: slippage at the pipe wall and fluidity based on behavior of the foam as a Bingham fluid. From the mathematical model, a computer program was prepared for effective field performance of stable foam.2"1"

Gas Drilling Benefits

From the controlled influx of natural gas to the injection of foam containing various functional additives, the primary objectives of reduced-pressure drilling have been to avoid loss of circulation and damage to productive formations. Other benefits have often been derived, however, such as faster drilling, improved bit performance, and ready detection of hydrocarbons. A survey of practices in 1977 was made by Hook, Cooper and Payne,278 and may be regarded as a summary of the state of the art at that time.


1. Brantly, J.E., History of Petroleum Engineering. Carter. D.V.. ed. Boyd Priming Co. Dallas, 1961. pp. 277, 278.

2. Brantly, J.E., History of Oil Well Drilling, Gulf Publishing Co., Houston. NT I . pp. 3, 38, 39.

4. Pennington, J.W., "The History of Drilling Technology and Its Prospects " Proc. API, Sect. IV. Prod. Bull. 235 (1949). p. 481.

5. Be art, Robert, "Apparatus for Boring in the Earth and in Stone," England, Patent No. 10,258 (Jan. 11, 1845).

6. Fauvelle, M., "A New Method of Boring for Artesian Springs," J. Frank lin Inst \ol. 12, 3 series (1846). pp. 369 -371.

7. Sweeney, Peter, U.S. Patent Records, U.S. Patent No. 51,902 (Jan. 2, 1866).

8. Chapman, M.T., U.S. Patent Records, U.S. Patent No. 443.069 (Dec. 16. 1890).

9. Hayes, C.W. and Kennedy, W., "Oil Fields of the Texas Louisiana Gulf Coastal Plain," U.S. Geol. Survey Bull, 212 (1903). p. 167.

10. Knapp, I.N., "The Use of Mud-Laden Water in Drilling Wells", Trans, \i\1i., vol. 51 (1916). pp. 571 586.

11. Pollard, J.A. and Heggem, A G., "Mud-Laden Fluid Applied to Well Drilling." U.S. Bur. Mines Tech. Paper 66 (1913).

12. Heggem, A.G. and Pollard, J.A., "Drilling Wells in Oklahoma by the Mud-Laden Fluid Method," U.S. Bur. Mines Tech. Paper 68 (1914).

13. Lewis, J.O. and McMurray, W.F., "The Use of Mud-Laden Fluid in Oil and Gas Wells," U.S. Bur. Mines Bull. 134 (1916).

14. Stroud, B.K., "Mud-Laden Fluids and Tables on Specific Gravities and Collapsing Pressures," Louisiana Dept. Conservation Tech. Paper No ! (March, 1922).

15. Stroud, B.K., "Use of Barytes as a Mud Laden Fluid," Oil Weekly (June 5, 1925). pp. 29-30.

16. Stroud, B.K., "Application of Mud-Laden Fluids to Oil or Gas Wells. I S. Patent No. 1,575, 944 and No. 1,575,945 (March 9, 1926).

17. Harth. P,E,, "Application of Mud-Laden Fluids to Oil or Gas Wells." U S Patent No. 1,991,637 (Feb. 19, 1935).

18. Parsons. C. P., "Characteristics of Drilling Fluids." Trans. AIME, vol. 92(1931). pp. 227 233.

19. Anon . "Determining the Comparative Values of Clays for Use in Drilling Muds." Drilling Mud, vol. 1, No. 1 (March, 1931).

20. Suman, J.R., "History of Petroleum Engineering," Carter, D.V., ed., Boyd Printing Co., Dallas, 1961. pp. 65 -132.

21. Collom, R.E., "The Use of Mud Fluid to Prevent Water Infiltration in Oil and Gas Wells," Summary of Operations California Oil Fields, vol. 8, No. 7 (Jan.. 1923) 26 84.

22. Collom, RE,, "The Mud Problem in Rotary Drilling," Part I. Oil Weekly (June 21. 1924), pp. 37-50; Part 2, Ibid. (July 5, 1924). pp. 45 50.

23. Knapp, A., "Action of Mud-Laden Fluids in Wells," Trans AIME, \of 69 (192.1). p. 1076-1100.

24. Kirwan, M.J., "Mud Fluid in Drilling and Protection of Wells,"' Oil ll'wkl\ (July 5, 1924). p. 34.

25. Cartwright, R.S., "Rotary Drilling Problems," Trans. AIME, vol. 82 (1928). pp.

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