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# Prepared Discussion of : 

# Recovering Valuable Byproducts from Oil
and Gas Wastes

Discusser: JOHN SCHUBERT, P.E,
HDR Sarasota, Florida

The authors of this paper are to be congratulated for presenting a paper on an
area which has heretofore not received a great deal of attention. That is the handling and disposition of drilling fluids from oil and gas well installation. The information presented provides a picture of how these materials are handled, which is quite
informative to those of us who do not work with drilling fluids every day. Thank you authors for presenting this paper.

That said, there were some areas where additional information, or more complete or supporting information would be valuable in helping the reader understand the operations that are described. A list of some of the questions that occurred to me while reviewing the paper include the following:

1. The typical Marcellus Shale well might use 4,000,000 to 5,000,000 gallons (95,000 to 120,000 bbl) water in hydrofracturing with flowback of maybe 20% of that. In comparison, what rate is mud circulated in a drilling operation, and what rate is typically wasted, both on an ongoing basis and as a total volume during the drilling event ? 2. In WBM, how much of the clay present is added as bentonite or other purchased clays versus the amount picked up in drilling typically ? For muds that have a high amount of clay from the formations being drilled, can that material be reused ? (I.e. does it have similar fluid properties and shape to the purchased bentonite.?) 3. In describing the benefits of oil based muds (OBM ?), the authors
state one benefit is enhanced shale
inhibition. What does this term
mean ?
4. In the section titled “Well Head Drilling Fluid Treatment” the authors
indicate that due to the volume of drilling fluid required it is most economical to reuse drilling fluids to the greatest extent possible. Can the authors provide some indication of the cost to prepare drilling fluid, and the usage rates as outlined in question 1, so that the reader can appreciate the economic incentive
for reuse.
5. What is the downside of reuse ? Does the use of virgin drilling mud provide any benefit in terms of energy utilization, bit life, or drilling speed ?IWC 13

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6. In the section on Well Head Drilling Fluid Treatment, several comments
are made relative to the
concentration of solids after screening, the content of oil, and the dewatering of solids to form a cake. Some typical numbers to support these positions would help the reader more fully understand the drivers for the handling processes selected. Particularly useful would
be the solids concentrations before and after screening, the typical flowrate through a screening station,
and the solids concentration in the
cake. The concentration of hydrocarbons in the various streams
would also be of interest. The screen sizes typically used would also provide insight into the nature of the solids at various points in the system.. 7. The fluid passing through the screens is noted as containing large amounts of solids. Is there a typical range of values that might be expected for this ? 8. In Table 1, the solids content of the mud entering the system is indicated as 6%, with a concentration of solids in the mud returning from the system
of 4%. This would seem
counterintuitive if the mud is increasing in solids in the drilling process, by collecting cuttings. 9. Is the weight of sludge wasting controlled only by the particle size distribution, or are there any other factors that govern the wasting rate
? 10. The paper indicates that screenings
from OBM can be blended with coal and burnt for energy, or subjected to thermal desorption. What types of operations can use coal blended with drill cuttings as a fuel source ? Is the hydrocarbon content of the screened cuttings sufficient to prevent disposal of the material directly ?. Can the material be washed with a detergent or extractant to remove the oil prior to disposal ? 11. Would clays from wasted mud be
handled in the same fashion as cuttings (i.e. thermal desorption)? One would think that drilling mud solids, being relatively fine, would retain some hydrocarbons on the substantial surface area they provide. 12. Did Holo-Scru pay for product placement in this paper ?
13. What are carbonate based coagulants ? 14. At the example treatment facility, are drilling mud wastes handled separately or together with flowback and produced water ? 15. The product water from the treatment system is noted as being sold, but would have a high sodium
chloride content. It is not stated but implied that it is sold for hydrofracturing use. Are there any
other uses for which this water is
sold ? 16. How much of the 1 MGD capacity at the example treatment facility is dedicated to handling drilling muds ? Can the facility accept oil based
muds as well as water based muds
?

A larger overall question relates to the title of the paper. The issue is that the paper is identified as being focused on recovering valuable byproducts. Yet there is littleIWC 13

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mention in the paper of the value of any of the byproducts. While it is reasonable to assume that the oil has a value, and that the cuttings have little value, there is little in the presented information to convince anyone the byproducts actually have a value. The key driver appears to be disposal cost minimization, and not byproduct value. In that respect, the disposition of mud solids (clays) is probably key to the discussion. The paper implies that attrition of solids in drilling limits the amount of mud that can be recycled and dictates the wasting rate. However, the final page of the paper
indicates that the mud solids can be recycled. Some explanation of how the finer solids generated through initial use in drilling are reused, and the value of the material, should be provided.

Again, the authors are to be congratulated for bringing this subject to the attention of the attendees. This is a subject that is rarely discussed, and presents unique handling/treatment Requirements.