Balancing waste management and solids control performance as part of total fluids cost

As oil and gas wells are drilled, a by-product of the process is drill cuttings. As the drill bit cuts its way deeper into the earth, an engineered drilling fluid removes formation solids from the face of the bit and carries them to the surface. To maintain the integrity of the drilling fluid, the cuttings must be removed continuously. This is best accomplished by mechanical separation methods called solids control.

Fig. 1. Solids control variables must be properly evaluated to achieve minimum cost.

Once the cuttings are separated from the fluid by solids control equipment, various waste management practices are employed to dispose of the cuttings. Total value should be defined as safely drilling a well with the lowest combined cost of fluid, solids control, and waste management. Therefore, choosing the right balance of where money is spent is critical.

There is a litany of variables to consider for an effective waste management program, all with pros, cons and costs. The operating company must evaluate those variables and create key performance indicators that make the most sense for its drilling program and area, Fig. 1. This article does not address drilling fluid engineering, but it does allow the reader to become acquainted with factors and considerations required to optimize solids control performance and costs. Additionally, it provides system evaluation examples.

DRILLING FLUID

Drilling fluid plays a crucial role in overall drilling success. Fluids are made up of liquids, chemical additives, and commercial solids (desired solids). These products have associated costs that can constitute 8% to 12% of the drilling budget for a typical land well.

Previously, formation pressures and drilling fluid costs were primary factors in deciding which mud system to use. As technology advanced, low-cost mud systems were replaced by pricier, high-performance systems that promoted faster drilling with desired wellbore integrity. This expensive fluid is discarded with cuttings by means of solids control equipment, when the rig is circulating and/or drilling. Understanding the interaction between drilling fluid and solids control equipment is necessary to balance solids control performance and waste management.

SOLIDS CONTROL

Solids control is the process in which drilled solids are separated from the drilling fluid. The best method is mechanical separation, predominantly with shale shakers, which are typically the only machines that process 100% of circulating volume. Other equipment, such as de-sanders, de-silters, and centrifuges, can then be used to further clean the drilling fluid. The primary goal is to mechanically remove as many undesired low-gravity solids (LGS) as possible. The secondary goal is to discard solids, as dry as possible, to minimize mud lost on cuttings.

Fig. 2. Optimizing the mechanical removal of low-gravity solids, as well as the discarding of solids (as dry as possible), minimizes dilution requirements and haul-off costs.

Optimizing these two functions minimizes dilution requirements and haul-off costs, Fig. 2. In conjunction with these costs, Solids Removal Efficiency (SRE) and mud loss ratios also can be measured.

Is 100% solids removal the best solution? Perfection sounds great, but when it comes to drilled solids, there are several factors to consider. First, 100% is easily achieved by routing all returns into a straight pipe that dumps into the waste bin. This process, however, will continually reduce your overall mud volume. The cost to replace this mud volume would be extreme.

Effective solids control systems may remove >90% of undesired LGS. Optimized shale shakers with fine screens will contribute the most removal. Operators should be pushing for the highest percentage of SRE while closely evaluating the costs to achieve this goal.

Dilution. If only a percentage of solids are mechanically removed, the remaining solids must be mitigated by dilution. Enough fluid must always be in the active system to fill the hole volume drilled. All volume additions beyond what is required to fill the hole are known as dilution. There are two main causes for dilution—drilling fluid added to lower LGS percentage in the active system, and drilling fluid built to replace what was lost on the cuttings discarded.

Dilution rate is the volume of fluid required for a target concentration of solids:

(V_ds = volume of drilled solids)

A high percentage of solids should be eliminated from the circulating system while, at the same time, reducing the amount of mud lost with these solids. Again, this is done by operating solids control equipment at peak performance.

Shakers to centrifuge: Discard and recovery. Consider the discussion in an earlier paragraph—removing more solids from the system causes a major decrease in the amount of dilution needed to treat the drilling fluid than would otherwise be required, if those solids were allowed to remain in circulation. The purpose of a shale shaker screen is simply to reject cuttings and separate them from the drilling fluid. The smaller the opening in the screen, the wider the size range of solids rejected.

From an economic standpoint, it is best to work toward a high rate of solids removal by the shakers, rather than deal with an enormous dilution bill. That said, shale shakers will only remove a certain size range of cuttings. Depending on the type of system being used, there may be a few other pieces of equipment needed, but a centrifuge is always recommended.

Fig. 3. The total surface area of all the small cuttings is greater than that of the original, larger cutting. Therefore, more mud has adsorbed to them.

Colloidal particles (microscopically blended) are the primary target of a centrifuge operation. These solids will negatively affect the fluids’ plastic viscosity and are too small for separation by fine screening. Again, in terms of balancing the fluid program, it is best to operate the unit to achieve excellent solids discard while also tracking surface mud loss.

Cuttings size. Drill cuttings size is determined by many variables, including formation type and depth. From the time they are formed and enter circulation, cuttings will, undoubtedly, go through a size reduction as they spin, crash and grind on their trip up the wellbore. Ultimately, the size of the cuttings discarded at the surface affects the amount of mud lost.

Total surface area of cuttings is inversely related to cuttings size. Imagine, for a moment, a cutting roughly the size of a 1-in. ball bearing. This cutting will, undoubtedly, absorb some of the drilling fluid, due to its inherent thirst for water. Additionally, the outer surface of the cutting has electrical charges that can attract the electrical charges on water molecules. The outcome is a cutting that is fully coated with an adsorbed boundary layer of fluid.

Now imagine this cutting being broken into pieces that are buried in the viscous drilling fluid. The total surface area of all of these small cuttings is greater than that of the original, larger cutting. Therefore, more mud has adsorbed to them than the original cutting, Fig 3. Less-viscous fluids result in thinner boundary layers, which equal less adsorbed drilling fluid discarded with drilling waste.

Drill solids are not the only particles that have this cause-and-effect relationship. Commercial solids, such as clays, weighting agents, and lost circulation materials, also break down and begin to bond with the drilling fluid. Many of these particles are microscopic in size, meaning a high surface area per unit volume.

WASTE MANAGEMENT

Reducing the wetness of drilling waste being hauled off typically lowers waste management costs, and can be achieved in several ways. It can be done using coarser screens on the shale shaker, using secondary solids control equipment (drying shakers, centrifuges, vertical dryers), and by adding drying material to the waste before it’s loaded into trucks.

Using coarser screens on the shale shaker will, most certainly, lead to less fluid loss, but the active circulating system will have a higher solids content because of the larger screen size. This is not preferred, because it will result in increased dilution costs. The benefits of secondary solids control equipment’s increased cuttings dryness must be quantifiable and out-weigh the daily rental cost. If not implemented correctly, this equipment can increase the solids content of the mud system, which again leads to increased dilution costs. An operator may not only be paying for the extra equipment, but also for increased dilution.

Finally, drying material can be added to the waste before disposal. This reduces the wetness of the cuttings without affecting the mud system’s properties, but it increases total haul-off and disposal volumes. Below are a few commonly used methods for drilling waste disposal—each with advantages and disadvantages.

Cuttings burial. A simple but rarely used option for cuttings disposal is to bury them on site, near the well pad. Many factors determine if this option is possible, such as drilling fluid type, land owner consent, etc. The advantage to burying the cuttings on site is eliminating the need to haul the cuttings away from the wellsite. This eliminates safety concerns, cost, coordination, and personnel associated with trucking and logistics. For these reasons, burying the cuttings on site is typically the easiest, cheapest option, but it does come with some liability.

Land fill. Most other options for drill cuttings disposal involve transporting them to an off-site location, usually by truck. One such destination is a landfill. These landfills contain engineered burial cells in which the cuttings will eventually be entombed. Landfill sites usually require cuttings and other drilling waste to pass a dryness test (U.S. EPA Paint Filter Test 9095B and/or U.S. EPA Liquid Release Test 9096). For this reason, cuttings that arrive to the landfill site “dry” usually have a lesser fee than wet cuttings.

Land farm. Like a land fill, a land farm also involves logistics from the wellsite to a land farm location. Instead of burying the cuttings, a land farm mixes the cuttings with soil for future agricultural use. Cuttings from wells drilled with oil-based muds (OBM) are usually acceptable, with an oil-on-cuttings percent (OOC%) of 3% to 5%. The less biodegradable the OBM is, the lower the recommended OOC%. Again, dryness of cuttings waste helps determine the disposal fee.

Biodegradation/composting. Another option for cuttings and waste disposal is hauling the waste to a biodegradation or composting site. This operation involves creating large windrows of the waste and mixing in compost material(s), such as wood, straw, rice or manure, to increase the mixture’s porosity and water retention. The windrows are tilled periodically to increase their aerobic state and promote faster bioremediation. The addition of compost material also increases the temperature retention of the piles, again speeding up the biodegradation process.

Cuttings reinjection. Cuttings reinjection is a method where cuttings are ground down and mixed with water, or some other fluid, to create a slurry, which is then pumped downhole and into a permeable geological formation. The targeted geological formation into which the cuttings are pumped must be mechanically and geologically isolated from any water source. The formation also must have good permeability and porosity, so that the cuttings slurry can be injected successfully without fracturing the formation. In general, cuttings that will be re-injected do not need to be dried in any way, as they will be ground and mixed into a slurry that can be pumped. This is an advantage of this disposal option, although dryness for trucking purposes must be examined.

Thermal desorptioninvolves heating the cuttings (commonly from oil-based fluid), so that the liquid phase is separated from the solids. Once the liquid exceeds its boiling temperature, it is evaporated off the solids. From there, it is condensed back into liquid form and separated into its two phases: water and oil. The equipment involved is expensive and requires a large footprint. Thermal desorption units only separate the liquid from the cuttings. Disposal of the cuttings still must be considered.

TRANSPORTATION

As land drilling continues to extend out to more remote areas, logistical considerations increase. Most logistical needs will be met by means of trucking. When deciding how to dispose of drilling waste, trucking costs and efficiencies must be kept in mind. The distance between the rig and the facility will play a big factor in deciding which facility to use. This distance will impact cost, logistical efficiency, timing and safety.

Trucking cost will either be charged by distance or time. Logistics will be more efficient to and from the rig site, when shorter distances are involved. This allows drivers to make multiple trips with one truck, as opposed to fewer trips with more trucks. When hauling oil-based waste specifically, a “wash out” of each truck will be required after the job is done. This cost is charged to the oil company.

In areas such as West Texas, the demand for trucking is greater than the supply. This leads to a shortage of trucks and lengthy required lead times. With that in mind, many operators are willing to pay standby costs for trucks just to be able to ensure they have a truck when needed. This cost is yet another factor to contemplate.

Cuttings “wetness” is also a consideration when selecting which type of truck to use. Three common types of trucks used to haul waste are open-top, enclosed trailer, and vacuum trucks. Open-top and enclosed-trailer trucks present a spill risk, therefore limiting the volume per load, resulting in an increased number of trucks used. Vacuum trucks are air-tight but cannot handle large cuttings, so they are typically selected to only haul fluid waste.

Drier cuttings can lead to lower overall logistical costs. However, if drier cuttings are achieved by using coarser screens, leading to a dilution increase, the total costs of fluid management may not be optimized. All these costs must be considered together, and balanced for maximum efficiency.

EVALUATING FLUIDS-RELATED EXPENSES

Imagine that you are monitoring the mud system balance on a rig that is drilling three wells on a pad. Assume that all drilling operations remain equal, other than how the solids control equipment is run. The basic drilling data are listed in Table 1.

Fig. 4. Overall costs associated with drilling three wells in West Texas.

Data from Fig. 4 reflect the overall costs associated with maintaining the three wells. The costs include scheduled screen checks and screen changes on shale shakers. All data and figures used in the calculations below were derived from drilling wells in West Texas.

All wells appear to have an acceptable SRE, with the difference being the amount of mud lost per barrel of solids discarded. Best practice is to balance SRE with cuttings dryness, rather than focus on one metric over another. The benefits of running a well-optimized system are apparent, when all costs are broken out, as in the example.

As previously mentioned, allowing drilling solids to remain in the circulating system is detrimental to drilling operations and expensive. In Well #1, failure to remove cuttings from the system resulted in most of the costs. This rig had a targeted 1:1 mud loss ratio, yet still had the largest haul-off costs. This was due to the large volume added to the system as dilution. Once reserve tanks were full, excess mud had to be trucked off location. Screen cost is minimal, when compared to these additional expenditures. Overall, this example emphasizes how one must analyze all aspects of solids control and waste management to improve operations and achieve minimal costs.

CONCLUSION

Like most complex processes, there are many variables to consider when improving costs associated with drilling fluids, solids control, and waste management. To understand solids control performance, there are key indicators like SRE, dilution rates, and mud-to-cuttings ratio, but overall cost is always most crucial. It is important to interpret the variables and factors presented in this article and work toward developing appropriate key performance indicators. This practice will help assess performance as a function of total cost efficiency. All factors are interrelated and essential to designing the most cost-effective plan for managing total fluids cost for a well.

NOTE

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