System and method for separating, monitoring and sampling coiled tubing flow back returns

Abstract

The invention relates to a system and method for separating, and safely monitoring and sampling flow back fluid returns from coiled tubing operations in oil and natural gas wells. The system comprises a flow back tank; one or more gas diffusers; one or more shale shakers; and a chute, which diverts flow from the gas diffusers to a sampling site positioned near the perimeter of the flow back tank. The system also has a volume level indicator on or near the perimeter of the flow back tank. The method comprises piping fluid returns from a wellbore, separating the trapped gases from the fluid returns, directing the degassed fluids to a shale shaker to separate the solids and directing the separated solids and liquids into separate tanks for analysis and reconditioning, if necessary. Cleaned liquids may be recirculated back to the wellbore.

Description

FIELD OF THE INVENTION

The present invention relates to a system and method for separating and real time monitoring of high pressure flow back returns during coiled tubing drilling and other oil and gas well operations, more particularly inspecting and sampling the returns and analyzing the samples to monitor downhole operational performance.

BACKGROUND OF THE INVENTION

In coiled tubing oil and gas operations, it is critically important to monitor the effectiveness of the downhole operations, particularly the condition of downhole tools and their work performance. This is especially important in coiled tubing operations, which circulate fluids and completion fluids under extremely high pressures. Conditions are encountered downhole that adversely affect the coiled tubing downhole operations. Tubulars can fail; tools break; debris from the formation mixes with return fluids; formations fracture; and other detrimental events can occur. Knowing what is happening downhole is important. Monitoring downhole activities, however, is difficult. Aside from using costly and lengthy fiber optics, it is not practical to physically view, in real time, what is occurring down a wellbore that may be thousands of feet in depth. Because of this predicament, there are two primary methods for monitoring the effectiveness of any on-going coiled tubing operation.

The first method is to measure the penetration rate and the coiled tubing string pressure. If the penetration rate or string pressure changes drastically, the operator will know that either the drill bit has been damaged, or the drill bit has encountered a different medium. However, by just measuring the penetration rate and string pressure, the operator cannot determine which of the aforementioned problems exist. Therefore, the operator must stop drilling and pull the coiled tubing string out of the wellbore to check the condition of the drill bit. Depending on the depth of the well, this can be extremely time-consuming, resulting in unnecessary delays, and further increasing costs.

The second method to monitor the effectiveness of the operation is to analyze the oil and gas fluids when they are circulated from the bottom of the well. The purpose of circulating the fluids back to the surface is to aid in the removal of all types of debris, which can include pieces of metal broken-off from downhole tools. Sand and earth, along with other debris, are also picked up by the fluid returns. The fluids are constantly circulated back up the annulus to a surface containment unit whereby debris gathered downhole are observed, monitored and removed. These circulated oil and gas fluids are often referred to as flow back fluid returns.

Under current methods, high pressure flow back fluid returns are piped from the well head into a gas diffuser to remove gases, and reduce the dangerously high pressures, which can sometimes exceed 12,000 psi. During this stage, the gas diffuser discharges gases into the atmosphere, and the remaining fluids fall down into a collection tank.

In order to measure the effectiveness of any downhole operation using this second method, an operator must collect grab samples from underneath the gas diffuser, also known as a gas buster, by precariously leaning over the tank rim and placing a collection container underneath the hot, circulating fluid that is being released to the atmosphere in great volumes. The operator then visually examines the grab sample to evaluate: the type of material being drilled, the physical properties of the fluid returns after circulation downhole to determine if additives are necessary, and the presence of any other unexpected substances circulated from the bottom of the well. Additionally, the operator can check the grab sample for metal shavings that might indicate any degradation of the downhole tool. This is especially useful because it allows the operator to stop the operation and bring the tool to the surface before more serious damage is done, which, if left unchecked, would result in even more down time and consequently, lost revenues.

However, this technique poses a serious safety hazard for the operator because of the fluid's high temperatures, often over 250° F., and high pressures. Also, depending on the circulating fluid's composition, the operator could encounter exposure to dangerous chemicals, resulting in various chemical burns or reactions.

Additionally, the circulating fluids used in hydrocarbon well operations are often re-circulated back down the well. Downhole, the wellbore fluids often pick up solid cuttings and debris, which must be removed if the fluid is to be reused. Using cleaner recirculated fluids allows for lower circulating pressures, and also results in less wear and tear on the tools and equipment that come in contact with the circulating fluid.

Collection tanks used in these operations are opaque, and therefore, the operator must walk up to the tank and lean over the rim in order to detect the volume level of the recirculated fluids inside the tank; posing another danger for the operator. The operator may be forced to walk out to the tank and either lean over the tank or climb a platform to periodically check the fluid level. These actions expose the operator to additional field hazards.

Consequently, in order to minimize the risk to the operator and increase efficiency when monitoring and analyzing flow back fluids, there exists a need for a system and a method that enables the operator to quickly and efficiently monitor the characteristics of the flow back fluids and volume of the collection tank without being subjected to any unnecessarily dangerous conditions.

SUMMARY OF THE INVENTION

The present method and system of separating, monitoring and sampling high pressure coiled tubing flow back fluid returns from oil and natural gas wells allows an operator to quickly and safely identify the physical characteristics of the flow back return fluids by minimizing the hazards facing the operator. The greatest danger lies in the need for the operator to monitor and sample the returns to understand what is happening down the wellbore, especially deep drilling and offshore wellbores where the returns are under pressures as high as 12,000 psi to 14,000 psi and greater.

In one embodiment of the system for separating, monitoring and sampling flow back fluid returns, the flow back fluids returning from the wellbore are fluids that contain gases, liquids having particulate matter and larger solids. The solids may include pieces of well cuttings and/or metal shavings from drilling tools and formation debris.

High pressure flowline piping is used to connect the wellbore to one or more gas diffusers, which are rigidly and removably attached to a flow back tank. A choke manifold, installed between the wellbore and gas diffuser, can be used to reduce the dangerously high pressures, which can sometimes exceed 12,000 psi. Advantageously, the connection between the wellbore and the gas diffusers has a means for a quick disconnect so that the gas diffusers can be installed rapidly. The gas diffusers remove the trapped gases from the fluid mixture, releasing them to the atmosphere with the rest of the fluid mixture exiting from portals positioned on the underside of the gas diffusers.

Preferably, a chute is fixedly attached to each gas diffuser to collect depressurized and decelerated fluid mixture. As a safety feature, the chute is positioned so that it directs the fluid towards the perimeter of the flow back tank. In one embodiment, a sampling site is located adjacent to the perimeter of the flow back tank and the chute is positioned for easier and safer monitoring and sampling of the fluid mixture leaving the gas diffuser. In another embodiment, a means for ascending the flow back tank is utilized to reach the top of the flow back tank. The means for ascending the flow back tank can include a stairway, a ramp, a ladder or a motorized stairway. Preferably, it is positioned adjacent the perimeter of the flow back tank and the chute in order to provide better access to the sampling site. In an alternate embodiment, a means for sampling the fluid mixture within the flow back tank, such as a sampling carousel, is used, and it is also positioned adjacent to the chute.

In another aspect of this invention, a volume level indicator is used to determine the volume of the liquid within the flow back tank. Preferably, the volume level indicator is visible up to at least 30 feet from the flow back tank and is positioned on or near the perimeter of the flow back tank so that an operator may determine the level of the flow back tank without having to precariously look over the edge.

In an alternate embodiment, after discharging the gases to the atmosphere, one or more shale shakers are used to separate the solids from the liquids as the fluids leave the gas diffuser. Preferably, the shale shaker is positioned adjacent the gas diffuser so that the fluid is discharged from the gas diffuser and directed into the shale shaker. The shale shaker separates the larger solids from the liquids within the fluid and sends the solids to a collection bin, while the liquids, which may contain some particulates, are directed to the flow back tank. In an alternative embodiment, a centrifuge may be used to separate the solid particulates from the liquids discharged from the underflow of the shale shaker. The system of this invention further comprises a liquids discharge channel to direct the liquids from the shale shaker to the flow back tank and a solids discharge channel to direct the solids to a collection bin. A safe means is also provided for sampling the liquids and solids after they leave the shale shaker in order to observe and analyze them to determine the conditions down the wellbore.

In another embodiment, a method for monitoring and sampling the flow back fluid returns of oil and natural gas wells begins with pumping fluid returns, brought up from the wellbore, to one or more gas diffusers. The fluid returns comprise gases, liquids and solids. The gas diffusers are rigidly and removably attached to a flow back tank. The gases are then separated from the fluid returns by one or more gas diffusers and released to the atmosphere. Next, the liquids and solids remaining within the degassed fluid are discharged from the one or more gas diffusers into a chute that directs the liquids and solids into a shale shaker, wherein the solids are separated from the liquids. The solids are sent to a collection bin via a solids discharge channel, and may be monitored and sampled as the solids travel down the solids discharge channel for analysis at a solids sampling site. The liquids are then directed into the flow back tank via a liquids discharge channel, where they may be monitored and sampled for analysis while en route to the flow back tank at a liquid sampling site. In another embodiment of the method of this invention illustrating a second safety factor, the operator can safely monitor the liquids and solids in real time by positioning a platform and means for ascending the platform adjacent the flow back tank to observe the liquids or solids coming out of the gas buster or shale shaker and take samples of the materials for further analysis. Either the liquids or the solids, preferably both, can be analyzed to determine changes in downhole conditions.

The liquids separated from the solids are often returned back down the wellbore to be reused in the oil and gas operations. A reconditioning tank can be used to treat the liquids leaving the shale shaker to refurbish the liquids prior to sending back to the well. In still another embodiment for additional safety, the operator reads a volume level indicator to determine the volume within the flow back tank at a distance from the flow back tank.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of the invention

FIG. 2 is a side view of the system of the invention

DETAILED DESCRIPTION OF THE INVENTION

Separating, monitoring, sampling and analyzing flow back return fluids are necessary steps in controlling the process of coiled tubing operations. Failing to perform these steps can result in catastrophic tool failure as well as degradation of fluids, thereby rendering the operation ineffective. The result is increased down time and escalated costs. However, current methods and systems used to monitor and sample flow back fluids can pose serious safety hazards for an operator, including burns caused by high temperatures and/or chemical compositions of the flow back fluid.

The present invention provides a method and system for safely separating, monitoring and sampling flow back returns in coiled tubing operations. Referring to FIG. 1, in one embodiment of this invention, coiled tubing 12, preferred in well interventions including subsea and horizontal wells, is inserted into a wellbore 17. The fluid is pumped into the well via coiled tubing 12, where it lubricates and provides power to the drill bit. The fluid also removes well cuttings from the bottom of the well before returning to the surface 11. The fluid, combined with any debris and gas that it has picked up in the wellbore 17, is known as flowback fluid returns 15. The flow back fluid returns are a combination of solids, dirty liquids, i.e., liquids comprising particulate matter, and gases. The fluid returns 15 travel from the wellbore 17 to one or more gas diffusers 20 using piping 19, 26. The piping 19 from the wellbore 17 is joined to the piping 26 leading to the gas diffuser 20 by a means adapted to connect 22 the piping 19, 26. In the preferred embodiment, a quick connect such as a hammer union 22 is used as the means to connect 22 the piping 19 from the wellbore 17 to the piping 26 leading to the gas diffusers 20.

As shown in FIGS. 1 and 2, the one or more gas diffusers 20 release substantially all of the gases 16 trapped in the flow back fluid returns 15 into the atmosphere, resulting in a significant reduction in pressure. The remaining degassed fluids descend from the one or more gas diffusers 20 into a chute 24 (illustrated by FIG. 2), where they are decelerated. This is an important safety measure since the decelerated and depressurized gases are less of a hazard to the operator. In embodiments in which the fluid is mostly liquid, FIG. 2, the liquid flows from the gas diffuser directly into the flow back tank 30. Alternatively, the fluids having a high solid content 33 are directed to an alternate gas diffuser and shale shaker unit where they are discharged from the gas diffuser 20 down into the shale shaker 40, FIG. 1. The one or more shale shakers 40 separate the degassed fluid into two separate streams: a solids stream 42 and a liquids stream 32. Gases discharged into the atmosphere may be sent to a scrubber to remove hazardous or odorous materials before leaving the system.

The solids stream 42 is directed into a collection bin 46 via a solids discharge channel 44, and the liquids stream 32 flows through a liquid discharge channel 37 into the flow back tank 30. The solids stream 42 may be observed and/or collected at the solids sampling site 48, which is positioned between the one or more shale shakers 40 and the collection bin 46. The liquids stream 32 may be observed and/or collected at a liquid sampling site located adjacent the liquid discharge channel 37. Alternatively, as seen in FIG. 2, a sampling point 36 may be used to collect a liquid sample from the flow back tank 30. In another aspect, a centrifuge can be used to remove particulates from the liquid stream 32. A means for analyzing 38 the liquids stream 32 in the flow back tank 30 is used in order to determine the physical and chemical properties of the liquids in the flow back tank 30, before recycling them back into the wellbore 17.

Careful monitoring by the operator of the liquid and solid stream 32, 42 in real time is critical in maintaining efficient oil and gas operations. By observing the types of solids that make-up the solids stream, the operator can quickly assess the types of materials that were in the bottom of the wellbore 17 as well as the physical characteristics of the fluids such as composition, viscosity, and the presence of undesirable materials, metal shavings or pieces of tools and equipment. One method for analyzing the materials for the presence of iron is the use of magnets positioned in or near the collection bin 46. Other analysis procedures for determining the physical and chemical characteristics of the fluids, including both liquid and solid content, are well known in the art. These procedures can be automated or manual. With this knowledge, the operator will be able to understand the chemical and physical events occurring downhole. For example, if metal pieces are found in the solids discharged from the shale shaker, and the metal pieces are determined to be from a drill bit, the operator will know that the drill bit has become degraded. This knowledge permits the operator to shut down the well operation before any additional damage can be done.

As illustrated in FIG. 1, the system 10 of this invention further comprises a system and method for monitoring in real time, sampling, testing and reconditioning the liquids so that they can be recirculated back to the well. The system of this invention comprises the step of observing and/or collecting a sample from the liquids stream 32 at the liquid sampling site 37. Problems downhole such as damaged tools and excessive wellbore debris can be discovered by simply looking at the fluids flowing into the flow back tank 30. Samples of the liquids stream 32 can also be sent to a means for analyzing and testing 64 the liquids stream 32 either as it is discharged from the shale shaker or once it is within the flow back tank 30. After the physical and chemical characteristics of the liquids are determined, the liquids are sent to a liquid makeup tank 38 for reconditioning the liquids. Careful monitoring of the liquids stream 32 is also important for successful well operations because, as mentioned above, an operator must know the composition of the liquids in the flow back tank 30 so that he can adjust the properties accordingly. The liquids 32 leaving the shale shaker may not have the composition and physical characteristics, such as viscosity, required for downhole operations. This is corrected in the liquid makeup tank 38 so that any liquids returned to the wellbore are reconditioned and corrected as to the fluids specification. The reconditioned liquids are then recirculated to the wellbore 17. Without this monitoring step, the resulting recirculated fluids might not have the correct fluid properties necessary to perform their downhole functions, for example: density and lubricating qualities. The problems associated with obtaining the samples such as injury to the operator are overcome by the safety mechanisms of this invention.

Referring to FIGS. 1 and 2, one safety characteristic comprises the rigidity of the attachment of the one or more gas diffusers 20 connected to the tank 30. In one aspect, piping from the wellbore is connected to piping 26 entering the gas diffuser 20 via quick disconnects 22, which are positioned adjacent ground level and allow the gas diffusers to be quickly hooked up or removed. The quick disconnects 22 allow the operator to efficiently get the process of recirculating downhole fluids up and running in a brief period of time. Another safety feature of this invention comprises a chute 24 that slopes slightly downward towards the perimeter 34 of the flow back tank 30 to a sampling site 36, which is positioned adjacent the perimeter 34 of the flow back tank 30. By using a chute 24 and directing the liquids stream 32 to the perimeter 34, the operator does not have to lean into the tank or be exposed to the high pressure fluids leaving the gas diffuser. The sampling site 36 is now an easily accessible area that allows an operator to gather samples in order to analyze the contents and properties of the liquids exiting the one or more gas diffusers 20. To further assist the operator in monitoring, sampling, and analyzing the liquids and solids coming from the wellbore 17, this invention also comprises a means to ascend 50 the flow back tank 30. Possible means for ascending 50 the flow back tank 30 include a stairway, a ramp, or a ladder. The means for ascending 50 the flow back tank further comprises a personnel access platform 54, which is positioned adjacent the area of the perimeter 34 approximate the chute 24. In one embodiment, the means for ascending 50 and the platform 54 are movable around the perimeter 34 of the flow tank 30.

Operators must keep track of the volume of fluids within the flow back tank. An additional safety feature is a volume level indicator 60 that is used to alert the operator to the volume level in the flow back tank 30 without the operator having to look over the side of the flow back tank 30. In the preferred embodiment, the volume level indicator 60 is made up of an external sight glass, which comprises substantially of a U-shaped cylinder that has two contiguous columns, where the first column is positioned internal to the flow back tank 30, and the second column is positioned external to the flow back tank 30.

The foregoing description of the preferred embodiments of the invention is presented for purposes of illustration and description, and is not intended to be exhaustive or to limit the invention to the precise form or embodiment disclosed. The description was selected to best explain the principles of the invention and their practical application to enable others skilled in the art to best utilize the invention in various embodiments. Various modifications as are best suited to the particular use are contemplated. It is intended that the scope of the invention is not to be limited by the specification, but to be defined by the claims set forth below.

Claims

1. A system for separating, monitoring and sampling flow back fluid returns in coil tubing operations for an oil and natural gas well comprising a wellbore, the fluid returns comprising gases, liquids and solids, the system comprising:

one or more gas diffusers for removing gases from the fluid returns;

means adapted to connect the wellbore to the one or more gas diffusers;

a flow back tank for receiving liquids and solids from each gas diffuser, the flow back tank comprising a perimeter;

a chute adjacent to each gas diffuser for collecting the fluid returns after the gases are removed, the chute slanted towards the perimeter of the flow back tank;

a sampling site positioned adjacent the perimeter of flow back tank for monitoring flow back fluids within the flow back tank; and

means for analyzing samples of flow back fluid returns to determine conditions down the wellbore.

2. The system of claim 1 wherein each gas diffuser is rigidly and removably attached to the flow back tank.

3. The system of claim 2 wherein each gas diffuser is rigidly and removably attached to the flow back tank with quick disconnects, the disconnects positioned adjacent ground level.

4. The system of claim 1 further comprising a means for ascending the flow back tank, the means for ascending the flow back tank is a stairway, a ramp, or a ladder.

5. The system of claim 4 wherein the means for ascending the flow back tank further comprises a personnel access platform, the platform positioned adjacent the area of the perimeter approximate the chute.

6. The system of claim 1 further comprising means for sampling the flow back fluids within the flow back tank, the sampling site for the means for sampling positioned adjacent the perimeter approximate the chute.

7. The system of claim 1 further comprising a volume level indicator to determine the volume of fluid within the flow back tank.

8. The system of claim 7 wherein the volume level indicator comprises an external sight glass, the external sight glass comprises a U-shaped cylinder, the cylinder comprising two contiguous columns, a first column positioned internal to the flow back tank, the second column positioned external to the flow back tank.

9. The system of claim 1 further comprising one or more shale shakers for separating the liquids and solids discharged from each gas diffuser, each shale shaker positioned to receive the liquids and solids discharged from the gas diffuser.

10. The system of claim 9 wherein each shale shaker comprises a liquid discharge channel so that the liquids are directed to the flow back tank and a solids discharge channel so that the solids are directed to a collection bin.

11. The system of claim 10 further comprising a liquid sampling site positioned between the shale shaker and the flow back tank for observing and sampling liquids leaving the shale shaker.

12. The system of claim 10 further comprising a solids sampling site positioned between the shale shaker and the collection bin for observing and sampling solids leaving the shale shaker.

13. The system of claim 10 further comprising a liquid treatment and makeup tank for reconditioning the liquids prior to returning the liquids to the wellbore.

14. A system for separating, monitoring and analyzing flow back fluid returns in coil tubing operations for an oil and natural gas well comprising a wellbore, the fluid returns comprising gases, liquids and solids, the system comprising:

one or more gas diffusers for removing gases from the fluid returns;

a means adapted to connect the wellbore to the one or more gas diffusers;

a flow back tank for receiving liquids from the gas diffuser, the liquids comprising particulate matter, the flow back tank comprising a perimeter;

the one or more gas diffusers rigidly and removably attached to the flow back tank;

a chute fixedly attached to the one or more gas diffusers for collecting the fluid returns after the gases are removed, the chute slanted towards the perimeter of the flow back tank;

a sampling site positioned adjacent the perimeter of the flow back tank for monitoring and sampling liquids within the flow back tank;

a means for ascending the flow back tank, the means for ascending positioned adjacent the perimeter of the flow back tank in the area of the chute;

a means for sampling the liquids within the flow back tank, the means for sampling positioned adjacent the perimeter approximate the chute;

a volume level indicator positioned on or near the perimeter of the flow back tank;

one or more shale shakers for separating the liquids from the solids discharged from the gas diffuser, the solids directed to a collection bin and the liquids directed to the flow back tank;

means for sampling the solids directed to the collection bin; and

means for analyzing the liquids and solids to determine conditions down the wellbore.

15. A method for separating, monitoring and sampling flow back fluid returns in oil and natural gas wells, the method comprising:

a. piping fluids from a wellbore to one or more gas diffusers, the fluids comprising gases, liquids and solids, the one or more gas diffusers rigidly and removably attached to a flow back tank;

b. separating the gases from the fluid returns within each gas diffuser and releasing the gases to the atmosphere;

c. discharging the remaining liquids and solids from each gas diffuser by directing the liquids and solids down a chute leading from each gas diffuser to one or more shale shakers;

d. separating the liquids from the solids as they pass through each shale shaker;

e. directing the liquids down a liquid discharge channel to the flow back tank and sending the solids down a solids discharge channel to a collection bin;

f. monitoring and sampling the liquids as the liquids flow down the liquid discharge channel; and

g. monitoring and sampling the solids as the solids flow down the solids discharge channel.

16. The method of claim 15 further comprising positioning a platform adjacent a perimeter of the flow back tank to facilitate monitoring and sampling of the liquids within the flow back tank.

17. The method of claim 15 further comprising analyzing the liquids after they are sampled to determine composition of liquids.

18. The method of claim 17 further comprising the step of reconditioning the liquids prior to returning the liquids to the wellbore.

19. The method of claim 15 further comprising visually inspecting the solids at a solids sampling site positioned between the shale shaker and the collection bin.

20. The method of claim 19 further comprising analyzing the solids to determine conditions down the wellbore.

21. The method of claim 15 further comprising positioning a volume level indicator on the perimeter of the flow back tank.