Drilling Fluids-Today and Tomorrow
- Jay P. Simpson (Baroid Div., N.L. Industries, Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1971
- Document Type
- Journal Paper
- 1,294 - 1,298
- 1971. Society of Petroleum Engineers
- 1.1.6 Hole Openers & Under-reamers, 4.1.3 Dehydration, 4.1.2 Separation and Treating, 4.2.3 Materials and Corrosion, 4.1.5 Processing Equipment, 1.11 Drilling Fluids and Materials, 1.6 Drilling Operations, 5.3.4 Integration of geomechanics in models, 1.6.1 Drilling Operation Management, 1.14 Casing and Cementing, 4.3.1 Hydrates, 5.2 Reservoir Fluid Dynamics, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.11.4 Solids Control, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties)
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Stuck pipe, excessive torque, bit balling, bridging, hole enlargement - all were problems that still existed even when a mud program was considered successful. The newer approach looks more to the condition of the hole and the interaction of drilling fluid and formation rock than to the funnel viscosity or the mud weight and achieves better control of these drilling bugbears.
"What funnel viscosity and water loss did you run?" The question was directed to a mud engineer who had assisted in getting a recent Williston Basin well drilled in record time. His answer would have shocked a lot of old-time mud men. "We didn't pay any attention to the funnel viscosity and water loss. We based our mud treatments on feet of hole drilled and on hole conditions." Such comments typify a growing attitude toward drilling fluids, The new attitude represents quite a change from an era just passed in which a mud program dogmatically specified the mud weight, funnel viscosity, and API filtrate. Then, the mud man at the rig worked to maintain those properties each tour by adjusting treatments that usually consisted of lignosulfonate, lignite and caustic soda. The mud control was considered successful if the specified properties were maintained and the mud costs were kept in line with those of nearby wells. In spite of the "successful" mud control, wells often were plagued with time-consuming and costly problems such as stuck pipe, excessive torque while problems such as stuck pipe, excessive torque while rotating the drill string, excessive drag while pulling the drill string, slow drilling because of bit balling, difficulty when running pipe because of bridging and hole fill, lost returns while running or pulling pipe, and difficulty in cementing pipe because of hole enlargement. These and similar difficulties were known to be related to wellbore instability. Extensive study and research were necessary, however, to relate borehole instability directly to the types of drilling fluid being used.
Borehole Stability and Shale Hydration
Although much has been learned about borehole stability, much remains to be learned. There are several reasons why progress in this area of research has been slow. Complexity of the formation rock has been a major factor in any attempts at research in the field. The formations to be drilled vary tremendously both as to mineralogical composition and stress conditions. Lack of unaltered formation samples makes it difficult to relate laboratory research to field conditions; there is no way that a sample of formation can be brought to the surface without altering the stress state and related properties of the rock. Another deterrent to research is the high cost. The equipment required to simulate borehole conditions is expensive both to assemble and to operate. Nevertheless, some excellent studies have been made in recent years. Wellbore instability has been related to shale hydration and resulting volume changes.
Shales, by definition, are rocks that contain clay and that have been compacted and partially dehydrated. The compacting force is the overburden load less the pore pressure for the particular shale. pore pressure for the particular shale. JPT
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