Correct use of solids control equipment is critical to maintain drilling fluid within its desired properties with the correct particle size distribution of solids and to avoid generation of unnecessary waste streams during drilling . Since the early 1930s the shale shaker has been the dominating device for primary solids removal. Additional equipment like desilters, desanders and decanter centrifuges were often used in the past to maintain proper solids control. Although it depends on the choice of correct shaker screens, at present most shakers have a sufficient performance to be in a position to act as the sole solids control device without the use of desanders and desilters.
The optimum solids control design for a particular drilling fluid may not be generally valid for all fluid types. A combination of shale shaker and shaker screens applicable for treating water based drilling fluids may for example not be suitable for treating oil based drilling fluids. Furthermore, the suitability of the screen and shaker combination may change during drilling because the drill cuttings morphology changes.
Throughout the last decades major shale shaker design improvements have been achieved. Circular motion shale shakers used up to the 1980s have been replaced by elliptical motion and linear motion shale shakers. Furthermore, integral cascade units like a double deck or triple deck shakers have been implemented in the industry. . Sinusoidal formed screens have been implemented on some shakers to increase the flow capacity. Different alternatives to shakers have also been tested to improve HES issues like hydrocarbon vapour and mist in the shaker room.
Shale shaker operation has also been automated. Scott claims that use of this automated system results in an increase in shaker screen life. However, Scott does not show the screen selection for this case. Therefore it is difficult to utilize this information in the present analysis. Removal of solids with a particle diameter larger than 120- 150μm, can be achieved without problems on most shakers today by the application of the correct screen size. There are many types of screen on the market.
Shale shaker efficiency is strongly dependent on the rheological properties of drilling fluids. The most important drilling fluid rheological properties for determining the shaker performance include viscosity profile, gel formation and extensional viscosity. In Arctic environments, the temperature at the shakers can be very low. These low temperatures may in many cases increase the viscosity and gel strength and thereby significantly reduce the shaker performance. In the following it is described how to maximise the flow capacity of different two deck shakers at the same time as the drilling fluid will be properly cleaned for drill solids.
Shaker screen selection
Earlier the shaker screen separation was determined by image analysis. The D50 size being the particle size where 50% of the particles will be transported through the screen and 50% were removed was named the Cutt point. The Cutt point is named after Cutt. In addition the D16 and D84 were also determined by image analysis. However, the image analysis is not very accurate because it cannot include the tortuosity of the screen flow paths. Often the wires are significantly thicker than the opening widths, implying that the errors can be large in case of multi cloth screens. Therefore, new standards has been recommended (American Petroleum Institute, 2010) where the D100 is determined based on experiments with aluminium oxide particles. Datta et al. measured the particle size distribution (PSD) using mixed sands to determine both the D50 and the PSD skewness. For a practical drilling operation where particle sizes are important, application of D100 is difficult. Omland et al. (2007) had to use both the experimentally determined D50 and the skewness to be able to optimise the drilling fluid for formation strengthening application. For information about how to strengthen the formation by particle addition, please consult Aston et al. (2004).
Selection of shaker screens
Based on practical experience and particle separation physics, Dahl et al. presented optimum operation of double deck shakers. The top deck should be set up with as fine mesh screens as possible to remove 95-98 % of the drilled cuttings. The bottom deck should be set up with the fines mesh screens as possible without being vulnerable for creating holes in the screen and as its primary function is to fine-filter the drilling fluid.
Current shale shakers are vibrating in a way that generates close to seven G in inertia forces. These high G forces still require a fairly thick drilling fluid level above the shaker screen to be efficient. It is straightforward to calculate the necessary inertia force to remove a gelled drilling fluid, or a drilling fluid with a yield stress, for a case with drilling fluid within the screen but without any fluid layer above the shaker screen. To create an approximation one can assume that a unit cell has the opening width equal to d, a wire thickness equal to D, a fluid density, r, and a gel strength tg. For a gelled drilling fluid to be able to flow through the screen, the screen must have an acceleration, a, sufficiently large such that mass times acceleration becomes larger than the gel resistance of the same volume. This gel resistance can be approximated by a four walled cube with a height equal to the wire thickness. The relation of these forces is described in Equation 1. ρd²Dg>4dDτg
If it is assumed that the density is that of water, gel strength is 5Pa and that the opening width is 75 micron the necessary G force number to remove this volume of drilling fluid would be 26.7 G or similar to the gravitational force at the surface of the visible sun. This calculation is an inaccurate approximation of course. Even with as much as 50% error the calculation still shows G forces twice as the forces produced on current shakers. It is therefore reasonable to anticipate a different mechanism for the flow through the shaker screens.
A series of experiments showing the effect of vibration superpositioned onto a shear flow of drilling fluids. They added three levels of vibration onto the cup of a standard viscometer. As expected from rheology fundamentals they did not observe any effect of vibration on viscometer readings if a simple polymeric liquid was evaluated. This is shown in the left hand figure of Fig. 1. If a particle suspension or an emulsion like the oil based drilling fluid was evaluated, however, a significant difference was observed. This is shown on the right hand figure of Fig. 1. The vibration quickly removed the yield stress or gel stress of these drilling fluids. These drilling fluids now became low viscosity fluids that were easier to flow through the screen. At this point the effect of the G forces re-enter the analysis, because now it is important that there is sufficient G forces to increase the flow of this non-gelled fluid, at the same time as the G forces were sufficiently small not to break up cuttings particles.
Optimised efficient flow area of double deck shaker top screens
Normally the drilling fluid returning from the well enters the upper deck of the shale shakers with a horizontal momentum co-current with the direction of the shale shaker’s vibration directions. In this way, the back part of the shaker’s upper screen is poorly used for separation. Furthermore, the fluid has a momentum reducing the contact time onto this upper deck screen. A method developed by Dahl changes the inflow direction from the header box to counter-current to the screens vibration direction. The system is illustrated in Fig. 2. The left hand part shows the device mounted onto the shakers on a Det norske operation and the right hand part shows an illustration on how it was used on a Statoil operation. This device has been applied both on Det norske and Statoil operations in the North Sea and significantly increases the effective separation area of the top screen as well as increase the contact time of the drilling fluid onto this screen.
Table 1. Effect of changing the flow direction into the shaker top screen in accordance with Dahl (2011). The comparison is based on measurements of drilling fluid on cuttings and low gravity solids made in accordance with industry standards (American Petroleum Institute, 2005).
|Increase in capatiy||~100%||~160%|
|Shaker screen reduction||>80%||>90%|
|Reduction in drilling fluid on cuttings||>60%||>60%|
|Reduction in personnel exposure time in the shaker room||~50%||~50%|
|Reduction in drilling fluid low gravity solids||~40%||~40%|
In both operations the improvements made from changing the inflow direction were significant. The inflow is shown in Fig. 3. On the left picture it is shown how the flow splashes in along the shaker screen close to the centre of the shaker screen. When the inflow device was used, the flow changed direction and the flow was distributed more evenly across the shaker screen.
The results of using the shale shaker inflow direction modifier device in accordance with Dahl are shown in Table 1. The results are from field operations in the North Sea for the Norwegian operators Det norske oljeselskap and Statoil. Two different shale shakers were applied. The shale shakers used in the Det norske operations were by far the oldest. For both operations the capacity is increased, shale shaker screen wear is reduced and drilling fluid properties are properly maintained. All these effects lead to a less need for personnel being in the shaker room; thus leading to less exposure to hydrocarbon damp and mist.
As is shown in Table 1, it was possible to significantly increase the capacity of both shale shakers. This implies that if one shaker is operating with less than maximum capacity, it is possible to use finer screens on the shaker’s top deck. The consequence for arctic operations is that cold drilling fluid is handled significantly better than in absence of the inflow device.
Consequences for triple deck shale shaker performance
The use the shale shaker inflow direction modifier device in accordance with Dahl (2011) on a three deck shaker is anticipated to give similar effects. It is anticipated to be less need of capacity increase. However, proper use of screen sizes on such machines will also contribute to reduced need for manual work on the shakers. Like for two deck shakers, screen wear is anticipated to be reduced.
Field experience has demonstrated that by implementation of a shale-shaker inflow direction modifier device it is possible to:
- Increase flow capacity of the shakers.
- Reduce shaker screen wear.
- Reduce the volume of drilling fluids on cuttings.
- Reduce low gravity solids in drilling fluids
- Reduce the need for personnel exposure in the shaker room.
The increased flow capacity makes it easier to handle cold drilling fluids like in the Arctic areas.
A significant cost issue is related to solids control ant the affiliated waste production during drilling. This cost issue includes the reduced drilling efficiency due to poor solids control when the drilling fluid temperature is low. The primary solids control device is the shale shakers. The preferred shakers have two or three decks that all separate particles from the drilling fluid. Especially when the temperature is low, the flow through the screens on these shakers is limited leading to a large discharge of drilling fluid along with the drilled cuttings.
To increase the efficiency of the shakers a new header box is developed that change the direction of the drilling fluid entering the shakers top deck. On several North Sea operations this device has successfully been used to divert the flow onto the entire top deck screen. This made it possible to run the equipment with finer screens than usual; leading to operating with cleaner drilling fluids than usual and thereby faster drilling rate at the same time as the occupational hygiene in the shaker room was significantly improved. The paper describes in detail how the shakers were modified with the header box and how the shakers were run to optimise drilling performance even when the drilling fluid was cold.