Patent Application
20210093984
The present disclosure relates to a separator for separating a used drilling slurry, removing liquid hydrocarbons from the drilling solids, and providing a reusable drilling fluid stream.
Drilling fluids are used during a drilling operation to cool a drill bit and to flush out the drill cuttings. In hydrocarbon wells, the most common drilling fluids are water-based or hydrocarbon-based. When drilling a hydrocarbon-producing well, the cuttings will often be oily cuttings. A shale shaker is used to remove some of the liquid from the cuttings, but the result is a slurry of cuttings, liquid hydrocarbons and drilling fluid that must be disposed of. U.S. Pat. No. 5,093,008 (Clifford, Ill.) entitled “Process and apparatus for recovering reusable water from waste drilling fluid” describes how water may be recovered from the drilling fluid.
Applicant's Canadian patent no. 2,694,811 teaches a system of tanks and valves presenting a multitude of configurations for providing a reusable drill fluid, separating solids from drilling fluid and providing a clean recirculating fluid back to the system.
Environmental regulations such as, for example Alberta Energy Regulator Directive 050 dictate that solids drilling waste (i.e., solids) must be essentially hydrocarbon free in order to be disposed of by landspreading. While technology exists, such as Applicant's previous patent, to clean the drilling fluids of drill solids, the drilling solids waste is often still significantly contaminated with hydrocarbons from the drilling operation.
Contaminated drilling solids waste is expensive to dispose of and a challenge to sufficiently clean to meet landspreading and other purposes.
A need therefore exists in the art for a dedicated system for cleaning drilling solids wastes of hydrocarbon residue, to form a non-contaminated solids product.
A separator is provided for removing hydrocarbons and fluid from solids from a slurry, the separator comprising:
A method is further provided for removing hydrocarbons and fluid from solids from a slurry, the method comprising the steps of:
These and other features will become more apparent from the following description in which reference is made to the appended drawings, the drawings are for the purpose of illustration only and are not intended to be in any way limiting, wherein:
A separator for separating liquid hydrocarbons, solids and fluid from a slurry, such as a drilling fluid used in a drilling operation, generally identified by reference numeral 10, will now be described with reference to
Structure and Relationship of Parts:
Separator 10 is intended to be used in separating the different components in a slurry that contains liquid hydrocarbons, solids, and fluid. For example, separator 10 is useful in separating components in a used drilling fluid, such as water or hydrocarbon based drilling fluids. As the drilling fluids exit a wellbore, there will be cuttings, such as sand or other products from the drilling operation, which may be coated in oil. Oil may also be entrained with the drilling fluid without being coated on the cuttings. Separating the components allows the cuttings to be disposed of more easily and also allows the drilling fluid to be reused. In industry, the drilling fluid is first passed over a standard rig shaker, which generally uses screens and vibration to remove some of the larger cuttings from drilling fluid. Separator 10 described below is preferably located after the rig shaker to receive the fluids after the larger cuttings have been removed.
In the description below, separator 10 is discussed with reference to used drilling fluids. However, it will be understood that separator 10 may be used for other slurrys, such as those that exist in tailings ponds, which are made up of hydrocarbons, suspended solids, and water.
Referring to
Solids from a lower end of first separator tank 12 are pumped via pump 74 to a first centrifuge 20 fed that removes at least a portion of the solids from the used drilling fluid and returns the used drilling fluid to first separator tank 12. Solids from the first centrifuge 20 are in this way significantly cleaned of hydrocarbons. If the hydrocarbon content of the solids is sufficiently low, then solids can be fed directly to a shale bin 60 via line 70 and valve 28. In an optional embodiment samples can be taken off of centrifuge 20 at predetermined intervals to determine hydrocarbon content.
If hydrocarbon content of solids from first centrifuge 20 is higher than a given threshold value, the solids can be fed again via line 70, but this time by valve 26 to a second separator tank 18 and from there to a second centrifuge 22. Referring to
The Applicants have found that the first centrifuge 20 can create a solid product that is anywhere from 95% to over 99% free of hydrocarbons. Should second centrifuge also be used, hydrocarbon content can be further removed by anywhere from 1% to 5%. As such, the solid product resulting from the present separator 10 system is a dry, clean solids product that can be used for any number of purposes such as agriculture, construction, civic projects and others. The present system takes drilling waste solids, which typically are a cost to dispose of, and cleans them into a saleable product.
As illustrated in
Referring to
Down stream of first and second separator tanks 12 and 18 are one or more settling tanks. As shown, preferably there are two sets of two settling tanks 40 and 42 in series with first separator tank 12 and settling tanks 44 and 46 connected in series in relation with second separator tank 18. Each settling tank has an inlet 48 that receives the used drilling fluid from the next tank upstream. Tanks 40 and 42 each also have an outlet 50 that outputs the used drilling fluid to the next settling tank. Settling prevents foamed liquid hydrocarbons from passing through outlet 50, and allows foam to instead be skimmed from the top of each tank. More preferably foam can be extracted by a vacuum line from a top surface of each of tanks 12, 18, 40, 42, 44 and 46.
Settling tanks 44 and 46 are not connected to another downstream tank. Each settling tank 40, 42, 44 and 46 is also connected to line 30 near a bottom of each tank, for example as shown in
Pump 38 may have an outlet 56 to capture the separated drilling fluid to be stored in a drilling fluid holding tank 62 and used to replenish the drilling fluid being used in the drilling operation, or to provide relatively clean fluid via line 58 to wash the rig shaker 19 and prevent a build-up of cuttings in its collection trough.
Between operations, line 30 together with pump 38 can be used to flush out the entire separator 10 system. In such cases, valves 52 just upstream of pumps 74 and 76 are closed and all other valves 52 are opened to allow fluid from separator and settling tanks to be pumped empty by pump 38 and then valves at the lower end of each tank can be closed and the tanks filled at least in part with a base fluid.
Preferably, settling tanks 40, 42, 44 and 46 are designed such that there is a minimal amount of disturbance to allow solids to settle.
Referring to
Referring to
As mentioned above, paddles 32 are used to agitate fluid in separator tanks 12 and 18, although other types of agitators may also be used. As depicted, fluids are circulated through separator 10 to be treated continuously. An injection port 54 allows flocculants to be injected into the system via line 36. The flocculant encourages the fine particles in the cuttings to be agglomerate, making them easier to remove. Captured solids or cuttings from screen 15 can also be output into a waste stream such as shale bin 60.
In a preferred embodiment, six tanks are used—two separator tanks 12 and 18 and four settling tanks 40, 42, 44 and 46. As shown, each tank is connected to the other adjacent tanks in series. By controlling the flow between inlets and outlets with valves or gates 47, the flow path through separator 10 may be changed.
Additionally, a heater system 64 may be fluidly connected to the separator tanks 12 and 18 via either the injection line 36, or by separate lines (not shown) to heat fluid in the system to help separate hydrocarbons from the solids. Valves 66 and 68 may be operated to control the fluid connection between line 36, the heater system 64, and chemical tank 54. Ideally, the heater system 64 is capable of heating 30 cubic meters of fluid to 70 degrees Celsius within a few hours and maintain that temperature in minus 50 degrees Celsius ambient temperature.
Operation:
In operation, drill cuttings or solids are introduced into separator tank 12 where they are agitated by agitator 32 and heated with heated water by a flow through the line 36 by pump 70 to separate hydrocarbons from the solids. As the fluid flows from tank 12 to tank 18, the solids settle to the bottom of the tanks, where they are drawn by pumps 74 and 76 and fed to centrifuges 20 and 22.
Separator 10 is intended to be used at a drilling site. Accordingly, it is preferably skid-mounted for ease of transport. Referring to
From first separator tank 12, fluid moves through settling tanks 42 and 44 and fluid also moves from second separator tank 18 to settling tanks 40 and 46 as each respective upstream tank overflows into the next downstream tank. As discussed above, the actual flow path through the various tanks may be changed by selectively opening and closing gates 47. In each settling tank 40, 42 and 44, the foamed oil will float to the top, while the solids settle to the bottom. Generally, the heavier solids will be removed by centrifuges, while settling tanks 40, 42, and 44 target the fines. The settling solids fall toward the sloped bottom, where they are removed by having centrifuge 20 or 22 draw from that tank. Fluids from each settling tank move on to the next settling tank. From settling tank 46 and also tank 44, the fluid is drawn off through outlet 56 to replace drilling fluid used in the drilling operation and to wash out the rig shaker. The process is therefore a continuous process that is driven by the newly deposited used drilling fluids, while diluting those drilling fluids in the base fluid and the separated fluid.
Cuttings removed by centrifuges 20 and 22 are more cleaner, drier and more easily disposed of relative to traditional methods as they are now a saleable sand product, useable for example as playground sand. At the same time, since drilling fluid is recovered by the process, it reduces the amount of new drilling fluid that needs to be introduced into the drilling operation.
It may be that second separator 18, second centrifuge 22 and second series of settling tanks 40 and 46 are not required for full removal of hydrocarbons from the drilling solids and solids are merely collected from first centrifuge 20 into shale bin 60. In such cases, the second separator tank 18, second centrifuge 22, and settling tanks 40 and 46 can be connected to a drill rig's active system to clean drilling mud before deployment downhole. This process, sometimes known as mud polishing, serves to remove ultrafine particles from the mud before it is used in the drilling process.
In this document, the word “comprising” is used in its non-limiting sense to mean that items following the word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one of the elements.
The following claims are to be understood to include what is specifically illustrated and described above, what is conceptually equivalent, and what can be obviously substituted. Those skilled in the art will appreciate that various adaptations and modifications of the described embodiments can be configured without departing from the scope of the claims. The illustrated embodiments have been set forth only as examples and should not be taken as limiting the invention. It is to be understood that, within the scope of the following claims, the invention may be practiced other than as specifically illustrated and described.
