Read the first part of this article here.
The Heart of Common Solids Control Failures
Drilling fluid conditions inevitably degrade over the course of the well. Theoretically, there are means to keep this from happening. However today’s modern solids control techniques, specifically those involved in traditional barite recovery operations, make the degradation impossible to avoid. This is driven by two common drill rig operator and solids control service provider errors:
- Coarse Flow Line Shaker Screens - Most drilling rigs operate their primary flow line shakers with screens that are far too coarse (rated at American Petroleum Institute [API] 120 or lower) to achieve meaningful solids control. Many factors cause this selection, and we now find ourselves in a viscous industrial cycle.
To cut costs, drilling rig operators use coarse screens that last longer and require significantly less personnel attention. Further, coarse screens minimize the risks of whole mud losses when drilling fluid circulation rates are high. However, the risk of whole mud losses would be significantly reduced, if a sufficient number of shakers, creating sufficient surface area, were installed.
By using coarse screens, drilling rig operators have become more reliant on solids control service companies to maintain the drilling fluid performance and ultimately the rig’s rate of penetration. Most drilling rig hands do not understand that usually, the wetter the solids discharge from the flow line shakers, the higher quality solids cut is being achieved. This is especially the case when drilling through reactive hydrophilic soils.
- 25 Percent Centrifuge Slip Stream Treatment - The application of centrifuges continues to target a 25 percent slip stream, where a minority of the circulation rate is routed to the centrifuge treatment systems. Even though most rig drilling fluid circulation rates will operate between 800 and 1,500 gallons per minute, the largest centrifuge applications treat 100 to 300 gallons per minute. The general impression is that a constant stream of fluid is being cleaned from the active system, therefore constantly removing colloidal solids. Unfortunately, most centrifuge applications fail to treat the full circulating volume.
As highlighted by Figure 3, most centrifuge applications treat only one out of four parts of the drilling fluid during each pass. Modern drilling techniques constantly generate colloidal and ultrafine solids through the natural degradation cycle, faster than can be removed by the solids control system. Ultimately, during each cycle of the drilling fluids, those three out of four parts not treated by the centrifuges will further degrade and be joined by more colloidal solids from the drilling process. If only one out of four parts of the further-degraded drilling fluid stream is treated during the next pass, the centrifuge systems will struggle to remove the low gravity solids being generated. How long would it take for a boat to sink if it was taking on water at a rate of four buckets a minute and only dump one bucket a minute could be dumped?
The combination of these factors results in modern drilling rigs operating with primary flow line shakers that are far too coarse to sufficiently support the goals of the solids control program and using insufficient centrifuge capacity to make up for the poor performance of the shaker systems. The suspended solids found in drilling fluids, as noted by Mr. Bouse, “are subjected to conditions that cause a progressive reduction in particle size, with a corresponding increase in surface area. This has serious adverse effects on mud quality even though solids content remains constant.” Even though if the mud weight stays the same, the surface area inevitably rises as the drilling fluid ages. In fact, it is possible for mud weigh to decrease, but still have the plastic viscosity increase as a direct result of elevated levels of colloidal solids.
The Heart of Common Barite Recovery Failures
For years, the traditional economic justification for using centrifuges with weighted drilling fluids has been based on the savings realized by barite recovery. The assumption is that recycling barite will save money. But more importantly, the concentration of ultrafines and colloidal particles rise at a much faster rate when centrifuges are not deployed. This inevitably leads to high-plastic viscosity, which leads to poor drilling fluid quality, which leads to downhole issues. One stuck pipe can cost the drilling rig operator much more than the total cost of the drilling fluids being used on the well. Controlling colloidal solids provides a much higher value than attempting to lower raw barite costs.
In a barite recovery system, the first centrifuge operates under the practice of traditional centrifuging, which means the underflow is returned to the active mud system to recover barite. The overflow, containing the majority of the colloidal solids and ultrafines, is then diverted to the high-speed solids control centrifuge. Instead of discarding the ultra-fine and colloidal solids feedstock to the entire drilling fluid system, it is submitted for supposed treatment, which allows only clean, colloidal-free drilling fluid is returned to the active drilling fluid system.
The mistake of this practice is better understood when considering that centrifuges do not efficiently cut suspended solids from the drilling fluid stream that are less than 5 μm. Though centrifuges capable of achieving 2,400 G can indeed theoretically cut solids down to 2 μm, the effectiveness of making that cut is dictated by the formation solids reactivity, level of drilling fluid inhibition and the general make-up of the drilling fluid. In fact, depending on the suspended solids properties and level of drilling fluid inhibition, achieving a 5-micron cut may require significantly more than 2,500 G’s of energy.
The barite recovery concept is fundamentally flawed as a result of two erroneous assumptions:
- The first centrifuge is capable of intelligently separating barite from low gravity solids
- The second centrifuge is capable of producing a colloidal, solids-free liquid for return to the drilling fluid.
As noted by Eugene E. Bouse in his May 4, 2013 E&P Magazine article titled “The Use and Misuse of Centrifuges,” “both of these assumptions are incorrect and ignore the physics of sedimentation.” More important is the assumption that the deployment of centrifuges in weighted drilling fluid applications has the objective of removing low gravity solids. This is not the goal. The goal is to remove colloidal and near-colloidal from the drilling fluid as soon as possible.
As noted by Bouse, “Using the ‘quick and dirty’ barite recovery concept to justify centrifuge rental is a simple, though flawed, calculation that has impeded the understanding of the real benefits of using centrifuges with drilling fluids.” Most modern centrifuge deployments are not only unproductive; they are counterproductive. This is because most centrifuge operators do not understand the life cycle of colloidal solids or how the systems they are operate interact with those colloidal solids. Bouse notes that the most common form of centrifuge misuse is “the practice of running two centrifuges in series to ‘recover the barite’ with the first and ‘discard the drilled solids’ with the second.” The colloidal and near colloidal solids are the predominant influence on a drilling fluid’s plastic viscosity and are so small that their specific gravity is barely relevant.
Understanding the Limits of Barite Recovery Relative to Colloids
Centrifugation is accelerated sedimentation using increased gravitational forces and is described by Stokes' Law. Equation 1 shows that the sedimentation rate is directly proportional to the difference in density between the settling particle and the surrounding liquid, and inversely proportional to the viscosity of the liquid.
As drilling fluids age, they contain both formation solids and drilled fluid solids that range from less than 1 μm to more than 100 μm (depending on the quality of the primary solids control achieved by the shakers). Assuming that the average specific gravity of barite and low-gravity solids particles are 4.2 and 2.6, respectively, the mass of a barite particle is equal to that of an LGS particle about 50 percent larger. For example, if most of the barite particles less than 6 μm remain in the overflow, then most of the low-gravity solids particles greater than 9μm will also remain in the overflow. The larger particles, both barite and formation solids, will be found in the underflow. Thus, barite is not separated from low-gravity solids. Heavier (larger) particles are separated from lighter (smaller) ones.
Consider what happens in the typical dual centrifuge barite recovery system. Assuming that the barite recovery unit makes an 10 μm cut on barite, and that the second high speed unit makes a 5 μm cut, most of the barite larger than 10 μm and the low gravity solids larger than 15 μm are returned to the mud at the first stage. At the second stage, the remaining barite larger than 5 μm and the low-gravity solids less than 7.5μm are discarded, and the finest, most damaging, material is returned to the drilling fluid.
As Figure 4 shows, no matter what the two cut points are, the material that is removed from the active mud system falls between them (approximately 5 to 10 μm). This fraction includes barite in a perfectly acceptable size range and low-gravity solids that are too large to increase plastic viscosity and too fine to be very abrasive. All of the finest solids, both degraded barite and cuttings in the colloidal and ultra-fine range, are returned to the mud system, assuring a progressive degradation in average particle size and in mud quality. The decreasing particle size increases the viscosity and the need for barite and solute dilution while diminishing wall cake quality and promoting the deterioration of hole conditions.
With viscous oil-based and synthetic drilling fluids, solids that behave like colloids can be much larger (10 to 15 μm). Their concentration must be controlled by dilution or by traditional centrifuging where the colloidal solids-laden centrate is discarded.
Based on the details presented, despite the addition of new barite and solute dilution, traditional barite recovery systems do not remove the solids directly affecting plastic viscosity. The mud engineer can continue to add new barite, but this does not change the volume of colloidal solids re-circulating through the system. The only way to reduce the colloidal solids content is to continuously purge the aged drilling fluid rather than introduce it to the second high-speed solids control centrifuge for further cleaning.
The desirably sized barite that is discarded by the high-speed solids control centrifuge must be replaced by fresh barite, 30 percent of which can be particles finer than 6 μm, and 10 percent of which can be expected to be colloidal (less than 2 μm). This further reduces average particle size and accelerates the decline of drilling fluid quality. So for every 10 pounds of new barite that are introduced, almost 3 pounds will pass through both centrifuges and build up in the drilling fluid, causing an inevitable rise in colloidal solids content and plastic viscosity. This is independent of the degradation effects that the solids will undergo throughout their well life cycle.
The return of centrifuge overflow to the mud system always involves the return of colloids. So this practice will always result in a progressive degradation of the suspended solids. As such, operators will commonly experience the need to increase the volume of drilling fluid being treated and exert higher amount of energy, in the form of G-force, in order to keep up with the drilling fluid condition.
The two-stage centrifugation process is expensive and, if not properly understood, can be harmful. By increasing the need for dilution, it increases mud cost and drilling waste volume. And it naturally reduces mud quality. The industry is currently led to believe that by running centrifuges in series we are recovering the barite at the first stage, and discarding the drilled colloidal solids at the second.
While most believe the liquid phase is too costly to discard and that any solids removal is value-added to the drilling contractor, remember that the problem solids are the finest particles. Adverse plastic viscosity and drilling fluid performance is the direct result of colloidal solids, not low gravity solids. Discarding the desirable solids needed to maintain the mud weight, while retaining the finest particles, does not alleviate the problem. It exacerbates it. Traditional centrifuging is preferred, but is hard to accept when it requires the continual discarding of centrate. This may not be necessary when the fluid is not used long enough for the colloidal concentration to increase to problem levels. However, when colloids do present problems, traditional centrifuging is the best way to restore mud quality.
Ultimately, the objective of centrifuging weighted drilling fluids is the removal of colloidal and near-colloidal particles, not the removal of low-gravity solids. Colloids are particles that are so fine that they will not settle in pure water. So regardless of the intent or energy used, they cannot be separated by centrifuging. Colloidal-rich centrate cannot be cleaned with centrifuges alone. And no practical field method to remove colloids from oil-based drilling fluids in which they are suspended exists.