Laboratory Drilling Rate and Filtration Studies Of Emulsion Drilling Fluids
- Charles P. Lawhon (Baroid Div. National Lead Co.) | William M. Evans (The U. Of Texas) | Jay P. Simpson (Baroid Div. National Lead Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 1967
- Document Type
- Journal Paper
- 943 - 948
- 1967. Society of Petroleum Engineers
- 1.2.3 Rock properties, 4.1.2 Separation and Treating, 1.6.9 Coring, Fishing, 1.11 Drilling Fluids and Materials, 4.1.5 Processing Equipment, 1.8 Formation Damage, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.6 Drilling Operations, 1.10 Drilling Equipment
- 1 in the last 30 days
- 507 since 2007
- Show more detail
- View rights & permissions
Data obtained under controlled lest conditions using a microbit drilling machine showed that oil emulsified in water muds may either increase or decrease the drilling rate, depending upon drilling conditions. A low-viscosity oil such as diesel fuel can give drilling rates in limestone almost equal to that of water. Data obtained for water emulsified in oil muds showed little increase in the drilling rate in water-saturated cares as the water percentage of the mud was increased above the 5- to 10-percent range. Changes in drilling rate were found to be dependent upon the oil or water concentration of the mud and upon the type of formation drilled. Changes in static filtration on paper (API filtrate) did not correlate with filtration while the mud was circulated across rock.
Oil additions to water muds have been reported to increase drilling rates, provide hole stability and improve filtration control. Eckel showed that water-base emulsion muds used in the West Texas area increased drilling rate with increasing oil concentration up to 15 percent oil by volume, but drilling rate decreased at a concentration of 20 percent by volume. Based on laboratory tests using water muds to drill shale, Cunningham and Goins reported that drilling rates increased and tendency for the bit to ball up decreased with the addition of oil. Percentage increase in drilling rate varied with the particular formation. They showed oil additions to improve drilling rates approximately 75 percent in Vicksburg shale and as much as 150 percent in Miocene shale. Each investigation showed an optimum oil content for the particular formation. Most data that indicated improved filtration control due to oil additions were based on static API filtrates through paper rather than dynamic filtration through permeable rocks. Some types of dynamic test give a better representation of filtration down-hole while drilling and might be more likely to show some correlation with drilling rate. Static filtration would be important, of course, in relation to hole stability and formation damage. This laboratory's drilling tests, conducted on water-saturated Berea sandstone, indicated that improvements in drilling rate were not evident with increasing oil concentration in water-base muds. Investigation also showed similarity between oil-emulsion (water-in-oil) muds and water- emulsion (oil-in-water) muds while drilling these formations. In Lueders limestone high concentration of water-in- oil muds and high concentration of oil-in-water muds provided the same relative drilling rates. In Berea sandstone there was a large reduction in relative drilling rate with both the oil and water muds that contained low percentages of emulsified fluid. Dynamic filtration rates of water muds on rock did not always decrease with increasing oil percentages even though the static API filtration rates on paper did decrease. Data observed in laboratory drilling of limestone and sandstone indicate that improvements in field drilling operations when water- or oil-emulsion muds are used may not be the result of increased drilling rates but of improved hole conditions. In some cases, actual drilling rates might be slower but improved hole conditions will result in less total time on the hole.
Mud pressure-Pressure of drilling fluid as measured after leaving the drilling chamber. This is considered as the approximate mud pressure just past the bit and at the face of the formation. Terrastatic pressure-Pressure representing weight of overburden. Formation pressure-Pressure of formation fluid as measured at outlet of drilling chamber. This is considered as approximate pressure of fluid in the pores of the formation. Differential pressure-Difference between the mud pressure and formation pressure. Relative drilling rate, percent-Drilling rate with experimental fluid divided by drilling rate with water times 100 equals percent.
LABORATORY EQUIPMENT AND TESTING PROCEDURES
The drilling equipment has been described in previous publications. The microbit drill is a closed system (capacity, approximately 7 gal) that can be pressurized to 15,000 psi and heated to 500F.
|File Size||558 KB||Number of Pages||6|