KEMTRON 600X™ is the Most Sophisticated Turn-Key Mud Recycling System on the Market Today
Elgin Separation Solutions pioneered the packaged mud recycling system decades ago. Operators quickly came to know these systems as durable, long-lasting, with high-quality sophistication and maximum performance.
Over the years, Elgin has continued to innovate these systems and was first to introduce a proprietary ‘Smart Panel’ control technology that provides full pump automation resulting in dramatically less operator attention. Advanced ‘Cruise-Control’ automation independently turn pumps on and off based on tank fluid levels to maximize pump life. In addition, an onboard Wi-Fi network provides full wireless system control from any Smart Phone, Tablet or PC. No competing system in the market provides for this level of system automation.
With the introduction of Elgin’s Hyper-G™ shaker in 2012, sticky reactive solids became manageable utilizing a dual-motion, variable speed vibrator motor configuration that is fully adjustable during operation without having to shut down. Patented ‘Water-Fall’ screen system design dramatically reduces the potential for solids bypass typically encountered by damaged screen gaskets, improper installation, and flooding of the rear screen by fluid. Additionally, the 6-panel, dual-deck design ranks highest in screening surface area compared to the competition.
New for 2020, Elgin’s KEMTRON 600X™ turn-key mud recycling system rises above the competition with improved design and performance today’s drilling contractors need to maximize operation.
Redesigned from the ground up, this unit features abrasion resistant slurry pumps with mechanical seal thermal siphon technology, high jet shear hopper mixing system, next generation composite wave screens, Tier-4 sound-attenuated generator package, onboard pressure washer with dedicated tank, ball valve flow control, hydraulic leveling jacks for quick onsite installation, ergonomic fold-up ladder and pump winterization access valves.
No other solutions on the market can outperform the new KEMTRON 600X™ Turn-Key Mud Recycling System. Increase your operation’s performance with the industry’s leading turn-key solution.
Abrasion Resistant Slurry Pumps
Rubber-lined slurry pumps are designed to dramatically improve both the pump life and ease of operation. Onboard thermal siphon system allows pumps to run dry without damage. No competing system in the market provides abrasion resistant centrifugal slurry pumps.
Next Generation Composite Pre-Tensioned Wave Screens
Elgin’s proprietary composite wave screens provide for 46% more surface area. Combined with Elgin’s dual-deck shaker, no shaker in the market provides for more screening surface area.
‘Smart Panel’ Control Technology
Designed with clean and dirty tank level sensors, the KEMTRON 600X™ provides full pump automation resulting in dramatically less operator attention. Advanced ‘Cruise-Control’ automation independently turn pumps on and off based on tank fluid levels to maximize pump life. Also available with full wireless control from any Smart Phone Tablet or PC. No competing system in the market provides for this level of system automation.
High Efficiency Jet Shear Mixing
Onboard jet shear system ensures efficient mixing of soluble polymers and bentonite used in water-based drilling fluids, therefore, eliminating “fish eyes.” Drilling fluid yield and gel strength properties are instantly obtained with hydraulic shearing of bentonite or organophilic clays.
Patented Screen Deck Design
Elgin’s Hyper-G™ shaker incorporates a patented “water-fall” screen system that dramatically reduces the potential for solids bypass typically encountered by damaged screen gaskets, improper installation, and flooding of the rear gasket by fluid. By having the discharge of each screen fall to the top of the next screen, the rear gasket area’s exposure to fluids is significantly reduced. This maximizes that performance of the shaker.
Hydraulically Operated Leveling Jacks
Elgin’s premium engineered trailers are designed for durability and dependability. Combined with hydraulic leveling jacks, no system can be deployed more efficiently.
Sound-Attenuated Generator Packages
Using Perkins™ engines and Stamford™ alternators, Elgin’s generator packages are provided with the industry’s most sound-attenuated generator enclosures.
Ball Valve Flow Control
Elgin has eliminated traditional gate valves and incorporated a series of ball valves to reduce valve washout and maintenance.
Built in access valves for easy pump system winterization.
Onboard Pressure Washer
Onboard pressure washer is calibrated for easy screens cleaning without damaging the wire cloth. Elgin’s newest KEMTRON 600X™ incorporates a completely independent polyurethane pressure washer tank.
Contact Elgin today and see how our turn-key mud recycling systems can maximize your operations.
Elgin Separation Solutions – Industrials, LLC (“Elgin”) Receives $13,000,000 Between Three Contracts for the Design and Engineering of Solids Control, Material Handling and Drilling Fluid Management Equipment for the Recently Merged Team of Megha Engineering & Infrastructure Limited (“MEIL”) and Drillmec Drilling Technologies (Drillmec).
Houston, Texas (USA) – May 18, 2020
Elgin is pleased to announce that it has been awarded a set of three contracts totaling $13,000,000 from the Recently Merged Megha Engineering & Infrastructure Limited (“MEIL”) and Drillmec Drilling Technologies (Drillmec). This contract comes at an especially exciting time and supports the solids control and drilling fluid management needs of 27 drilling rigs. These rigs are being built to provide advanced land drilling technology for Oil and Natural Gas Corporation (“ONGC”) Limited, the national oil company of India.
Given Elgin’s own Indian-based technical support and manufacturing center in Baroda, India, this opportunity provides the best combination of in-country value combined with high-tech engineering and project management. Via this contract, Elgin will be providing high-frequency shale shakers and mud cleaners, jet shears and venturi mud hoppers, hydraulically-driven 16” decanter centrifuges, and vacuum degassers.
Elgin’s success with this project could not have been possible, if it were not for the technical and commercial support provided by its world-class supply chain partners, including Netzsch™ Pumps Germany, Italvibras™ Vibrators Italy, Eaton™ Hydraulics America, Nord™ Gearboxes Germany, Adalet™ America, Siemens™ Motors America, Kem-Tron Technologies Pvt. India, and Yaskawa™ American Inc. As noted by Mr. Emad Babri, Executive Director of Engineering for Elgin Separation Solutions – Industrials, “The support each of these organizations have shown in the face of such challenging macro-economic times has been remarkable. Our success as an organization is directly attributed to the continued technical and commercial support these organizations have provided and continue to provide. We will continue to measure the quality of our own products and services through the strength and sophistication of our manufacturing partners.”
Founded in 1864, Elgin’s Industrial Products Division is Headquartered in Stafford, Texas. Elgin’s team includes design and manufacturing leaders that specialize in providing turn-key engineered systems for customers in more than 35 countries. As noted by Michael Rai Anderson, President of Elgin Separation Solutions – Industrials, “We could not be more excited for the opportunity to work with MEIL, Drillmec and ONGC. The opportunity to enhance India’s own energy infrastructure, through the deployment of advanced drilling and work-over rigs, is both humbling and an honor.”.
Elgin Separation Solutions is a turn-key solutions company in the Oil & Gas, Mining, Aggregate, Trenchless and Water Intake Industry. Contact us today to learn more about Elgin.
Understanding the Potential Class II – Division I Safety Hazards Present When Operating Vertical Cuttings Dryers
For decades, the industry standard for waste management dryers (a.k.a. vertical cuttings dryers) has relied on belt-driven sheaves. Though belt-driven systems are cost effective and relatively easy to implement, at a minimum they have represented a maintenance nuisance, at worst they represent a serious safety concern when improperly design and/or maintained.
Section 1 – Belt Hazards
Most belts available in the market today must meet the ISO 9563 standard for static conductivity. However, they are only required to meet the standard when new. As soon as the belts are in use, their antistatic properties dramatically decrease. At the end of their useful life, these antistatic properties are lost. However, the generation of a static electrical discharge is only one of the potential safety concerns; the generation of excessive heat when belts break or slip through overloading cannot be ignored.
Most belt-driven gear-box Operation and Maintenance manuals will include a number of warnings relative to the use of belts in potentially hazardous environments. One of the industry’s most common gear box manufacturers have included the following warning, “[We] do not support the use of our belt drive in explosion proof or hazardous environments. While the belt may be non-sparking, the belt drive assembly does not have a safety to disengage the belt. In the event of an overload the belt can slip and generate excessive heat.” However, it is not just belt-driven gear box manufacturers that have issued this warning. One of the industry’s most prolific suppliers of industrial belt-driven sheaves shares similar concerns, “Although [we] know of no explosion caused by static generated by a V-belt drive, we cannot accept responsibility beyond that of furnishing belts within the above described limits.”
Despite the evidence of a real safety concern and the volume of warnings that have been published, little reaction has mounted within the industry. The fact is that very few dryer operators are aware of the potential safety concerns and even fewer are trained to monitor and manage them.
Section 2 – Fire and Explosion Hazard Regulations
Outside the oil & gas industry, the dangers of combustible dusts have been long recognized. Powders, coal, and oil are normally quite stable in bulk form, but when dispersed as a cloud they can form an explosive mixture. All that is then required for an explosion to occur is a direct ignition source, which could be a heat source, frictional spark or an electrostatic discharge.
Indeed there are long established standards issued by the National Fire Protection Association (NFPA), the Occupational Safety & Health Administration (OSHA), Explosive Atmospheres (ATEX) Directives in Europe, and other national and international bodies that address the issue. Whenever standards have been implemented and compliance observed, it is clear that dust explosions have been reduced or eliminated, but it is also clear that implementation is not universal. This has become more obvious with the growing number of vertical cuttings dryers and related waste management devices entering the market from new entrants and the declining level of preventative maintenance being dedicated.
As it applies to the O&G industry, the Occupational Safety and Health Administration (“OSHA”), National Fire Protection Association (“NFPA”) Publication 70, and the National Electric Code (“NEC”), define two categories of hazardous materials that have been designated as Class I or Class II. The Classes define the type of explosive or ignitable substances which are present in the atmosphere. The specific definitions are as follows:
- Class I locations are those in which flammable vapors & gases may be present.
- Class II locations are those in which combustible dust may be found.
Each of these Classes is further subdivided into two Divisions, Division 1 or Division 2. The Division defines the likelihood of the hazardous material being present in a flammable concentration.
- Division 1 locations are those in which ignitable concentrations of hazards exist under normal operation conditions and/or where hazards may be caused by maintenance or equipment failure.
- Division 2 locations are those in which ignitable concentrations of hazards are handled, processed or used, but which are normally in closed containers or closed systems from which they can only escape through accidental rupture or breakdown of such containers or systems.
As is common for most oil & gas drilling installations, the common standard for capital equipment is Class I – Division 1. The omission of Class II – Division 1 specifications is predominantly driven by the fact that oil & gas drilling operations are not known to generate combustible dusts. This oversight is quite understandable this hazard is not readily obvious.
Specific to oil, oil mist becomes ignitable whenever it reaches the Lower Explosion Level (LEL), which is approximately 47mg/liter or 13% oil mist / air ratio.
Static electricity is the ignition source in approximately 10% of all chemical fires and explosions.
The US Chemical Safety & Hazard Investigation Board launched a wide ranging study of industrial dust explosions. They found that in the period 1980 to 2005 there were 281 dust fires and explosions in US businesses that caused the deaths of 119 people and injured 718 more. Since the study was undertaken there have been a further 70 dust fires and explosions in the US.
Section 3 – Improperly Maintained & Poorly Designed Dryers Present a New Risk
The hazards present, relative to belt-driven sheaves, is not new. A variety of oil-field products have used belts for decades; centrifuges and pumps are some of the most common. History tells us that the risk of igniting a fire from a static electrical discharge generated from these devices is extremely rare. However, waste management cuttings dryers present a new risk when improperly designed, operated or maintained due to the presence of a potentially combustible dust atmosphere.
By design, waste management cuttings dryers attempt to generate a dry solids discharge. When an optimized dryer system is capable of achieving a solids discharge, with a moisture content less than 3%, a high volume of dust can be generated. Though it is common for dryer installations to observe dust and oil mist (when treating oil-based cuttings) surrounding the dryer, the concentrations of these dusts and oil mist never reach a level that could be considered combustible or hazardous. However, it is what happens within the confines of the dryer that drives the concern. When the dryer is operating at peak performance, a confined cloud of dust and oil mist is generated within the body.
Historically, Elgin Separation Solutions has taken a great deal of care to encase anti-static belts and sheave systems within an enclosed “belt tunnel”. This is done for both safety purposes and to maximize belt life by protect the sheaves and belts from being exposed to the solids discharge. By having a fully enclosed belt tunnel, any electro-static discharge or heat source would not be in direct contact with a potentially combustible dust environment. However, over the years, Elgin has witnessed a number of VCD field installations in which damage was caused to this belt tunnel or when the belt-tunnel and gear box access doors were completely removed. Though the belts and sheaves were still predominantly protected from the falling solids discharge, any static-electrical discharge or heat source generated from damaged belts were fully exposed to a potentially combustible atmosphere.
More concerning is the growing number of new entrants into the market, especially those that are being imported from “low-cost country” sources. In many cases, these new entrants have poorly designed or completely exposed belt and sheave systems that provide no barrier between potentially combustible oil mist or dust and a static-electrical discharge or excessive heat source. Further, many of these same products lack any indication that their belts meet the ISO 9563 certification requirements. This does not always generate from a poor design, but from the fact that the country of origin may not have defined safety standards and laws requiring such protections.
Damage to the belt tunnel and/or missing access doors have not been the only concerns observed by Elgin. Elgin has witnessed other installations in which the continued use of belts, far past the appropriate replacement cycle, were being used, and has even observed the use of replacement belts that were not ISO 9563 certified.
Section 4 – Innovation That Ensures Safety, Minimizes Maintenance, and Lowers Operating Costs
The need for effective waste management is not going away. Besides the obvious economic advantages, related to the use of waste management dryers, the market conditions and our communities demand that such technology continues to be deployed. Given these drivers, it is up to the industry and the original equipment manufacturers to demand and design technology that is safe to use and economical to operate. Elgin Separation Solutions keenly understands the expectations of the market and has been diligently working to implement enhancements to its line of vertical cuttings dryers that can not only ensure safety, but also significantly reduce the typical complications experienced with belt-driven systems. How do you improve a belt-driven dryer?
Though there are a number of new belt technologies, belt-tensioning systems, and static-dissipation systems available in the market, none of these options improve the “operator experience.” These systems require constant maintenance and the exhausting effort required to periodically replace belts. Given these facts, Elgin Separation Solutions has designed a new direct drive dryer that completely eliminates the use of belts or the need to enter the body of the dryer for maintenance.
Elgin’s new patent-pending direct drive dryers incorporate a proprietary assembly that includes an alignment compensating drive shaft, greased-for-life 90 degree torque inverter, and the industry’s most durable and field-proven gear-box drive system. Not only does this technology eliminate the need to enter the dryer to service and maintain drive belts, but it provides guaranteed Class I – Division 1 and Class I – Division 2 compliant drive system. No other dryer available in the market can make those same claims.
Beyond the core compliance benefits and reduced maintenance benefits, Elgin’s Direct Drive Technology yields a number of unique benefits, including:
- The 90 degree torque inverter gear box reduces the power consumption and power transmission efficiency will increase.
- The direct drive gearbox is 99% efficient whereas V-belt sheaves are only 95% efficient, again improving power transmission.
- There will be no over-hung load on the motor bearings, thus extending the life of the motor.
- By eliminating the sheaves and belts, vibration and noise levels will be significantly reduced.
- By eliminating the large belt tunnel and motor mount assembly, the dryer is 160 pounds lighter.
Common Challenges Relative to the use of a Decanter Centrifuge for Barite Recovery in the Oil & Gas Industry
When decanter centrifuge is properly deployed, they can have dramatic effects on drilling performance. In fact, without them, many of the advances made in drilling would not have been considered achievable. Classically, we believe that centrifuges can achieve two common goals:
- Reduce the content of drilled fines, specifically colloidal solids, and
- Perform barite recovery in order to reduce drilling fluid additive costs.
Respectfully, each goal presents a valiant initiative. However, when combined they also present a number of complications that are typically overlooked by most modern solids control service providers.
In understanding these complications, it is important to recognize that the ultimate goal of a decanter centrifuge is to reduce the plastic viscosity of the drilling fluid. This improves the drilling rates of penetration and reduces the damaging effects of accelerated wear on bits, mud pumps, and related equipment. Further, if all goes as planned, by controlling the colloidal solids, significantly less mud make-up dilution is required. In essence, when properly used, a decanter centrifuge should enhance the drilling fluid properties, thereby improving rig performance (i.e. increased rates of penetration, improved cake wall stability, reduced bit torque and reduce pipe drag). Concurrent to these benefits, a decanter centrifuge can also be used to lower waste disposal costs by reducing the volume of waste drilling fluid and reduce raw material additive costs by maintaining the target properties of the drilling fluid. Generally speaking, this is the canned sales pitch offered to drill rig operators, used by solids control service companies, in order to market barite recovery and solids control services.
Despite these goals, the evolution of the drilling industry over the last few years has resulted in the rapid deployment of decanter centrifuges that are unable to achieve the results targeted or marketed. Though the centrifuges available in the market have indeed improved, modern drilling practices have evolved greatly in the last decade. Modern drilling rigs are continuing to set new standards by drilling deeper, faster, and longer (relative to the pervasive utilization of directional drilling techniques). Given the recent evolution of drilling, there are indeed concerns growing as to whether or not the application of a decanter centrifuge has evolved at an equal pace. In fact, it was almost 10 years ago when concern was initially raised by Eugene E. Bouse in his May 4th, 2013 E&P Magazine article entitled “The Use and Misuse of Centrifuges”. As noted by Mr. Bouse, “Unfortunately, misuse has become more common, and many of the costly present-day practices are so ill-conceived that they are actually detrimental to both mud quality and waste minimization efforts.” As will be carefully consider through the remainder of this document, Mr. Bouse was pointing to several concerns relative to barite recovery services.
A decanter centrifuge is deployed in order to “cut” solids from the liquid stream; essentially creating two separate streams from the incoming influent. We typically consider the cut to be the “underflow” (a.k.a. “solids discharge”, “cake”, and/or “heavy phase effluent”) and the cleaned liquid stream (a.k.a. “centrate” or “light phase effluent”) to be the “overflow”. The centrate will contain most of the liquid and the finer solids. The cake will contain less liquid and the coarser solids. The goal is to have the cake as dry as possible with the lowest volume of surface wetting liquid achievable. The ability to achieve this goal is a direct function of the drilling fluid inhibition, formation solids reactivity (defined as the combined measure of the potential for a material to cause a negative impact to the drilling activities by material hydration and/or dispersion), decanter centrifuge design parameters (i.e. conical section length, conical section inner diameter and beach configuration), and decanter centrifuge operating parameters (i.e. pond depth, g-force applied and conveyor speed). However, it is important to note that the goal of achieving a “dry” solids discharge should not precede the goal of achieving the proper colloidal solids cut. Table 1 highlights the physical effect each of these parameters has on the ability of the decanter centrifuge to make a cut.
The application of “Traditional Centrifuging” techniques removes both the ultrafine and colloidal solids regardless of their classification as formation solids (a.k.a. drilled solids, low gravity solids or LGS), or drilling fluid solids (a.k.a. weighting agents – most commonly barite). The goal would be to remove all suspended solids above a targeted particle size distribution, whereby new drilling fluid solids would be added to the system. Relative to Barite Recovery, the traditional intent is to maintain the larger solids, specifically barite and those solids classified by API as fine and ultra-fine (assuming that most medium, intermediate and coarse solids were appropriately removed by the primary solids control systems; the flow line shakers) for return to the drilling fluid.
As highlighted by Figure 1 and Figure 2, ultra fine and fine solids fall within the American Petroleum Institute’s (“API”) standard particle size distribution classification of barite.
Figure 2: Comparative Particle Size Distributions of Bentonite and Barite Relative to API Defined Particle Size Distributions and General Solid Control Equipment Capabilities
Section 2.0 – Defining Traditional Barite Recovery With A Decanter Centrifuge
For “Barite Recovery” operations, service providers pair two centrifuges together, in which the first decanter centrifuge targets solids between a 10 and 100μm range and the second and the second purportedly removes those solids less than 10μm. This 10 and 100μm range is the sweet spot within the particle size distribution curve for barite as highlighted in Figure 1. The lower end of this range (10μm) is set by the centrifuge’s applied G-force, where the upper end of this range (100μm) is set by the practical suspended solids cut achieved by the primary solids control system, the flow line shakers. The influent to the barite recovery centrifuge comes as a “slip-stream” from the active mud system. This means that the full circulation volume of the Active Mud System is not sent through the centrifuge system. The first centrifuge’s solids “cake” is returned to the Active Mud System with the goal of recycling barite, where the centrate (containing the colloidal and ultrafine solids) is plumbed to the second centrifuge.
The second decanter centrifuge is configured as a high speed centrifuge to remove low gravity solids. The target range rests between the maximum capability of the centrifuge, relative to the maximum achievable G-force that can be applied (typically 2 to 5μm), and the lower range defined by the barite recovery centrifuge. The solids “cake” is considered waste and is disposed of, whereas the “cleaned” centrate is returned to the Active Mud System. Figure 3 provides an illustration of the prototypical Barite Recovery Process using a decanter centrifuge:
Section 3.0 – Colloidal Solids and Their Effect on Plastic Viscosity
Understanding colloidal solids, especially as it relates to modern oil & gas solids control practices, is not easy task. Most decanter centrifuge operators do not understand that drilling fluids performance and the associated plastic viscosity are driven by the colloidal solids content, not “low gravity solids”. Even fewer operators understand the different between low-gravity solids and colloidal solids. However, when comparing them to every day rig terms, it can be easier to digest.
As highlighted in Figures 1 and 2, barite has a particle size distribution that ranges from 1 micron to 100 microns (predominantly ultra-fine and fine solids). API specifies that barite should achieve a size distribution where the percentage of material >75μm is minimized, while ensuring that the percentage of material <6μm is no higher than 30% by weight.
As for bentonite, the particle size distribution can range from under 1μm up to 10μm (colloidal and smaller ultrafine solids). As highlighted by Figure 2, bentonite solids have a much smaller particle size distribution in comparison to barite and hence the reason that bentonite is typically considered a “thickening agent” to increase viscosity, whereas barite is simply considered a weighting agent. Barite has only a modest impact on viscosity, as the aggregate surface area of the solids are dramatically lower than the surface area exhibited by the solids found in bentonite. This comes from the fact that the negative effects of elevated plastic viscosity are predominantly driven by the available surface area exposed by colloidal solids, which are highly prevalent in bentonite, in comparison to barite.
Despite the fact that the particle size distribution bands are fairly well defined, measuring solids within these ranges is complicated. The common mistake made by centrifuge operators is the reliance on a “retort” analysis. Though the retort is a practical tool to measure the total aggregate mud weight, it is useless for defining the change in plastic viscosity (i.e. increase in total surface solids surface area as it directly relates to an increase in the colloidal solids content) associated by the continued and natural degradation of drilling fluid and formation solids into colloidal solids. To meaningfully pinpoint the changing conditions (a.k.a. rheology) of the drilling fluids through the well cycle, details relative to the particle size distribution must be captured. Only a particle size distribution analysis can shed light on the total surface area exhibited by the drilling fluid suspended solids. As this test is not traditionally considered practical or “cost-effective” to complete on the rig site on a daily basis, most operators ignore it, in lieu of the more commonly adopted retort analysis.
Unfortunately, by relying on the retort analysis exclusively, centrifuge operators and mud engineers are unable to ascertain the characteristic life cycle of the colloidal solids. Many mud engineers will simply assume that when the mud weight increases, as defined by the retort analysis, the only logical option is to increase the treatment capacity of the centrifuges or increase the applied G-force. However, given the fact that the centrifuges are only treating a small percentage of the total circulating volume and that centrifuges are unable to manage colloidal solids, operators are left fighting a losing battle.
Section 4.0 – The Heart of Common Solids Control Failures
As noted in Section 1.0 and Section 2.0, drilling fluid conditions will 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 this 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 far too coarse (Screens rated at API 120 or lower) to achieve meaningful solids control. This is driven predominantly by a multitude of factors that are now caught up in a viscous industrial cycle. In order 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 (i.e. sufficient surface area) were installed. With all this said, the use of coarser screens on the flow line shakers simply supports the business models of drilling fluid additive providers and solids control service providers. 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. Oddly enough, most drilling rig hands do not understand that in most cases, 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% Centrifuge Slip Stream Treatment – The application of centrifuges continues to target a 25% slip stream (i.e. a minority of the circulation rate is routed to the centrifuge treatment systems). Despite the fact that 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, as illustrated by Figure 3, 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 4, most centrifuge applications treat only one out of four parts of the drilling fluid during each pass. The challenge is that 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 simply 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 your boat to sink if it was taking on water at a rate of four buckets a minute and you only have the ability to dump one bucket a minute?
The combination of the above 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 utilizing insufficient centrifuge capacity to make up for the poor performance of the shaker systems. Regardless of our desires, 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 the mud weight may stay the same, as the drilling fluid ages, the surface area inevitably rises. In fact, it is possible to have a drop in the mud weight, but still have an increase in the plastic viscosity as a direct result of elevated levels of colloidal solids.
Section 5.0 – 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. However, it is more important to understand that when centrifuges are not deployed, the concentration of ultrafines and colloidal particles rise at a much faster rate. As we have previously noted, this inevitably leads to high plastic viscosity, which leads to poor drilling fluid quality, which leads to a myriad of down-hole 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. The fact is controlling colloidal solids provides a much higher value than attempting to lower raw barite costs.
As discussed in Section 1, in a Barite Recovery System the first centrifuge operates under the practice of “traditional centrifuging”, whereby the underflow (a.k.a. “solids discharge”, “cake”, “heavy phase effluent”) is returned to the active mud system in order to recover barite. The overflow (a.k.a. “centrate” or “light phase effluent”), containing the vast 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”, whereby only clean, “colloidal-free” drilling fluid is returned to the active drilling fluid system.
The fallacy of this practice is better understood when considering that centrifuges do not efficiently cut suspended solids from the drilling fluid stream less than 5μm. Though centrifuges capable of achieving 2,400 G can indeed theoretically cut solids down to 2μm, the effectiveness of making that cut are 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; and
- The second centrifuge is capable of producing a colloidal, solids-free liquid for return to the drilling fluid.
As noted by Mr. Bouse, “both of these assumptions are incorrect and ignore the physics of sedimentation.” More important to these two erroneous assumptions, 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 absolutely possible.
As noted by Mr. 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.” The fact is that most modern centrifuge deployments are not only unproductive, they are counterproductive. This predominantly driven by the fact that most centrifuge operators do not understand the life cycle of colloidal solids or how the systems they are operate interact with those colloidal solids. As noted by Mr. Bouse, 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 fact is that 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”. This concept is explored in more detail in the next section.
Section 6.0 – Understanding the Limits of Barite Recovery Relative to Colloids
Centrifugation is accelerated sedimentation using increased gravitational forces and is described by Stokes’ Law. As noted by the formula below, it states 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 <1μm to more than 100μm (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% larger. For example, if most of the barite particles <6μm remain in the overflow, then most of the low-gravity solids particles <9μm will also remain in the overflow. The larger particles, both barite and formation solids, will be found in the underflow. Thus, we don’t separate barite from low-gravity solids; we separate heavier (larger) particles from lighter (smaller) ones.
Let’s consider what happens in the typical dual centrifuge barite recovery system. Assuming that the “barite recovery” unit makes an 10μm cut on barite, and that the second “high speed unit” makes a 5μm cut, most of the barite larger than 10μm and the low gravity solids larger than 15μm are returned to the mud at the first stage. At the second stage, the remaining barite larger than >5μm and the low-gravity solids >7.5μm are discarded, and the finest, most damaging, material is returned to the drilling fluid.
As is highlighted by Figure 5, no matter what the two cut points are, the material that is removed from the active mud system falls between them (approximately 5 to 10μm). 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.
It is also important to recognize that with viscous oil-based and synthetic drilling fluids, solids that behave like colloids can be much larger (10 to 15μm). Their concentration must be controlled by dilution or by traditional centrifuging where the colloidal solids-laden centrate is discarded.
Based on the details presented above, 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 versus introducing it to the second high-speed solids control centrifuge for further “cleaning”.
Worse yet, the desirably sized barite that is discarded by the high-speed solids control centrifuge must be replaced by fresh barite, 30% of which can be particles finer than 6 μm, and 10% of which can be expected to be colloidal (< 2 μm). This further reduces average particle size and accelerates the decline of drilling fluid quality. This means that for every 10 pounds of new barite that are introduced, almost 3 pounds of this material 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 (a.k.a. “centrate” or “light phase effluent”) to the mud system always involves the return of colloids; thus, 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. Even worse, 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.”
Section 7.0 – Decanter Centrifuge Challenges Conclusion
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 swallow 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; therefore, regardless of the intent or energy used, they cannot be separated by centrifuging. The punch-line is simply, colloidal-rich centrate cannot be “cleaned” with centrifuges alone. Worse yet, there is no practical field method to remove colloids from oil-based drilling fluids in which they are suspended.