Drilling advances

	Vol. 229 No. 2
LES SKINNER, PE, CONTRIBUTING EDITOR, LSKINNER@SBCGLOBAL.NET

Drill-in fluids

Drilling mud boiling up in a pit fascinates me. One could say I am mesmerized by it. I just like to see fluid moving-it’s very therapeutic. Soft billows of brown mud flowing gently to the surface. Ah, the pleasure, the rapture.

Then, I recall my days mixing mud through the hopper. What a pain! I recall the sacks, bulk volumes and strange chemicals the mud man and his best buddy, the toolpusher, forced us to mix through the working pit. The revelation strikes home that drilling muds are not like flowing rivers. They are, in fact, workhorses. Their residence in the pit system is only temporary. They will soon be sucked in by massive pumps and returned to their chaotic, high pressure job downhole.

We all know that mud is required to carry out cuttings, lubricate the drillstring and cool the bit, along with providing extra hydraulic horsepower through the bit nozzles. Improvements in drilling fluids have impacted almost all aspects of getting the hole deeper, cheaper. But what about the portion of the well that involves drilling into the producing reservoir? We’ve all heard about water-based and oil-based drilling muds for the upper portion of the hole, but what about the producing formation itself?

Many wells are now being drilled with synthetic oil-based muds (SOBM). I am told (not being a completions guy) that this stuff is awfully hard to clean out of the formation, even if it is trapped behind an easily-destroyed filter cake. It seems that there are reactions and adhesions of SOBM fluids to producing rock pores. SOBM delights in invading deeply into the formation and staying there. So, the benefit of drilling rapidly with minimized formation damage using SOBM is offset by the reservoir damage it causes.

The common solution is the use of solids-free, water-based drill-in fluid. In many cases, this fluid is displaced after setting the intermediate casing or drilling liner at the top of the producing formation. The drill-in fluid is used to drill through the remainder of the hole segment. All that is left is water-based fluid that everyone knows is less damaging than oil-based drilling fluid. Right?

Not so, turkey neck. Water-based drill-in fluids are usually not composed of formation produced water. The additives to provide viscosity, density, stability, fluid loss and inhibition are all foreign materials; each one is fully capable of reacting with in-situ formation fluids and clays resulting in compatibility-related damage to the primary rock permeability. In short, anything that contacts the formation that is not native to that rock will damage it in some manner.

History and experience have shown that highly inhibited, water-based drill-in fluids damage the formation less than oil-based fluids. Generally, halogen brines (made with chlorine and bromine salts) pickle reactive formations, particularly shales, by restricting molecular ion transfer between the rock and the drilling fluid.

Several major mud suppliers provide fully-inhibited, gelled, halogen-based drill-in fluid systems, and they are very good. I am told that these leave a minimal filter cake and damaged zone, and often a tiny acid wash is all that is needed to remove fluid-invasion damage. Clear brines have often been used for completion and workover fluids. Now they are being used for drill-in fluids.

The problem is that halogen brines can damage human skin seriously. There is no immediate pain associated with halogen brine exposure, so the victim doesn’t know they’ve been in contact with one of these fluids until long after they get it on them. It starts by burning away the surface skin layer, then working i’s way deeper and deeper through the skin sheath. The only way to stop the damage in severe skin contact incidents is to excise (cut out) the affected skin. Skin grafts and various treatment options exist for severe exposures, but the skin usually requires several months (up to five) to heal completely. Even then, prevalent scarring often results, and the damaged site is sensitive for life to future halogen brine exposure.

One remedy for this HSE risk is the use of formate brines. These cover the entire range of densities provided by the halogen brines, and exposures to these fluids produce nothing close to the damage caused by halogen brines, often none at all. Like most other materials with good properties and limited risks, formate brines are expensive (so is the loss of a person’s skin). Regardless, these formate brines provide a partial solution to the drill-in fluid selection dilemma.

Earlier this month, I was advised that my prior conceptions about oil-based muds were all fouled up. Several service companies have now developed non-damaging, oil-based drill-in fluids. Now, the same fluid used to drill the well segment just above the reservoir can be used to drill the formation. Once the well is completed, a simple enzyme treatment breaks chemical bonds within the mud matrix, allowing recovery of the filter cake and all the leftover drilling fluid.

The enzymes are oliophilic (oil-loving) and they destroy the drilling mud’s oil phase leaving it as a simple contaminant that flows back with the produced fluid. I was skeptical of enzymes as completion fluid cleanup additives, due to their short survival time at formation temperature. However, the experts tell me that my concerns are unfounded, and that these critters can remove essentially all fluid-induced formation damage. Oh, joy!

In one major operator’s study of oil-based drill-in fluids, native-state permeability was restored to over 96% by a simple enzyme/acid treatment in a US deepwater well. Another analysis indicated that essentially all the damage was removed. It seems that several technical papers discuss this phenomenon. Enzymes may be the way of the future. Needless to say, I am impressed. So, it seems we have finally found the cat’s meow for drill-in fluids. Or have we?

I am still a proponent of putting nothing on the formation except the fluid that came from it. I am looking for a non-damaging, water-based OR oil-based drill-in mud that uses native fluid as the base material. This fluid could be pumped around, recycled, cleaned up, reused and it would not damage the formation. Further, since it would be available on the lease, it should be inexpensive. To me, that’s the cat’s meow.

Once we perfect this magic fluid, we can start working on seawater. Stay safe out there, and don’t get anything on you that won’t wash off.