Patent Application
20170015899
At various times during the life of a well it is desirable to treat the well. Such treatments include drilling, cementing, perforating, fracturing, gravel packing etc. These treatments generally involve pumping fluid with a number of agents typically solids, into the wellbore. For instance when pumping a drilling mud the drilling mud may be a weighted or non-weighted water-based gel. When weighted, the weighting material may be a particulate such as barite.
One of the functions of a drilling fluid is to seal the wellbore so that the fluid is not lost into highly permeable subterranean zones penetrated by the wellbore. This is accomplished by depositing filter cake solids from the drilling fluid over the surfaces of the wellbore then dehydrating the drilling fluid in order to allow the solids to bridge over the formation pores while not permanently plugging the pores.
When drilling a wellbore, the drilling fluid is continuously circulated down the interior of the drill pipe, through the drill bit and back to the surface in the annular area on the outside of the drill pipe. At various points the wellbore may need to be cased. In this event circulation of the drilling fluid ceases while the drill bit and drill pipe are removed from the well and casing is run into the well. With circulation stopped gelled and dehydrated drilling fluid and filter cake is deposited on the walls of the wellbore.
Once the casing has been run into the well typically cement is pumped through the interior of the casing, out the bottom of the casing, and back up the exterior sides of the casing. With cement in the area between the exterior of the casing and the wellbore cement may harden bonding the casing to the wellbore thereby sealing the annular area and preventing fluid communication axially along the exterior of the casing. Unfortunately, the gelled and dehydrated drilling fluid and filter cake tend to provide a barrier between the cement and the desired bonding surface, either the casing or the wellbore, thereby preventing the cement from bonding the casing to the wellbore. Additionally, the drilling fluid is comparatively expensive therefore operators prefer to attempt to retrieve the maximum amount of drilling fluid from the wellbore in an effort to reduce costs. In an attempt to remove the remnants of the drilling fluid from the wellbore prior to cementing a fluid flush a clear fluid pad may be pumped through the wellbore.
Although high fluid permeability is an important characteristic of a hydrocarbon-producing formation, the permeability on the well may be adversely affected by loss of treating fluid into the formation. For example, in a fracturing or fracing treatment it is desirable to control loss of the treating fluid into the formation to maintain a wedging effect and propagate the fracture through the entire formation to improve its permeability. However, there are limitations on the amount of treatment fluid that is able to be pumped downhole at a sufficient pressure. Without a sufficient amount of pressurized fluid the portion of the formation having higher permeability will most likely consume the major portion of the treatment fluid leaving the least permeable portion of the formation virtually untreated. Therefore, it is desired to control the loss of treating fluids to the highly permeable formations during such treatments.
The efficient treatment of the wellbore, at times, requires temporarily reducing permeability of a portion of the formation to increase the availability of treating fluids to the less permeable portion of the formation in order to create a relatively uniform permeability across the formation, the formation zone, or several formations. Several fluid loss agents have been developed for use in these treatments.
Prior fluid loss control agents included dissolvable or degradable materials such as polyglycolic acid and polylactic acid solids. Such materials have been used as diverting agents that are dispersed in the treating fluid to temporarily reduce the permeability of a portion of the formation or a zone of the well. After the treatment is completed the diverting agents then dissolve and flow out of the well once the well is put on production. Unfortunately, these types of diverting agents require relatively high temperatures in order to dissolve. For example, both polyglycolic acid and polylactic acid solids require weeks to reach 80% degradation when the fluid temperature is low temperature or less than 160° F.
Therefore, there is still a need for a low temperature diverting agent which can effectively and temporarily prevent fluid loss including during treatment operations and is capable of being removed from a low temperature well after treatment operations without leaving any residue in the wellbore or in the formation.
In an embodiment of the invention isobutylene urea, methylene urea, or formaldehyde urea, well known as agricultural fertilizer, may be used as a diverting agent. Generally, very large amount of the diverting agent is loaded into the fluid system. Usually from between about 20% to about 50% by weight of the fluid system is the diverting agent. A viscosifier is added to carry the diverting agent into the formation. When these materials are used as a diverting agent they are able to flow into the formation zone of high fluid loss and restrict fluid flow through the formation zone. Then at least 80% of the material degrades over the next few days. As the temperature increases the rate of degradation increases and as the temperature decreases the rate of degradation decreases. However, it has been found that in the presence of a small amount of an organic acid catalyzing agent such as citric acid, acetic acid, or formic acid the rate of degradation at low temperatures, temperatures less than 160° F., is vastly increased. Typically, in the presence of an organic acid catalyzing agent, at least 80% of the material degrades within a few hours, typically 3 to 4 hours.
In practice, a well is identified where the temperature of the formation zones are less than 160° F. In such an instance the frac fluid is batch mixed in a slurry form on the surface with at least a viscosity enhancer that can be but is not restricted to guar gum and its derivatives, carboxymethylcellulose, cellulose derivatives, or polyacrylamide derivatives. Immediately prior, usually less than 10 minutes, to pumping the fluid into the wellbore an amount of the diverting material and acid catalyzing agent such as citric acid, acetic acid, or formic acid in either live or encapsulated form is mixed with the fluid. In some instances, such as when a greatly increased rate of degradation is desired, an inorganic acid, such as HCl, may be used as the catalyzing agent. Typically, the small amount of organic acid catalyzing agent is from about 5% to about 50% by weight of the diverting agent. The diverting material in solid form has a size particle distribution between 0.04 mm and 4.00 mm. As fluid is pumped into this formation zone of high permeability the diverting agent begins to seal off the fractures making them less and less permeable eventually causing the fluid to be diverted to a formation zone that was previously less permeable than the initial formation zone. The permeability of the second formation zone is then increased by the fracturing operation while at the same time being filled with diverting agent until the permeability of the second formation zone is reduced by the diverting agent so that the third formation zone is now the highest permeability of the zones to be treated. The fracturing operation is continued so that the third zone is fractured thereby increasing its permeability. After treating all three zones the permeability across each zone is relatively uniform. The process of treating the zones of the well may be repeated until the overall permeability of the desired zones in the well is increased. The diverting agent, in the presence of the catalyzing agent, begins to degrade such that 80% of the material has degraded within a few hours. Typically, the diverting agent that was initially placed will have degraded to the point where it can flow out of the well, once the well is put on production.
The description that follows includes exemplary apparatus, methods, techniques, or instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.
The fluid may be a mixture of viscosified water with guar gum, guar derivatives, carboxymethylcellulose, cellulose derivatives, polyacrylamide polymers, copolymers derivatives or combinations thereof. In certain instances, a friction reducer may be included, preferably carboxymethylcellulose. When low temperature degradation is required, such as when the fluid that is being restricted by the diverting agent is less than 160° F., a catalyzing agent that facilitates the degradation, dissolution, erosion, etc of the diverting agent is added to the fracturing fluid prior to the fracturing fluid being pumped down hole. Preferably the catalyzing agent is added approximately in conjunction with the fracturing fluid entering the wellbore. The catalyzing agent is an organic or inorganic acid but is preferably citric acid or acetic acid added in an amount of between 5% and 50% percent of the total amount of the diverting agent.
From the surface it is very difficult to determine which the amount of fluid that is pumped into a particular formation zone and a predetermined amount of fluid is pumped into the wellbore 10 to fracture the three formation zones 12, 14, and 16. Therefore if all of the fracturing fluid was pumped into formation zone 14 then formation zones 12 and 16 would not be treated or treated to a lesser extent than formation zone 14. However, in this example as more diverting fluid is pumped in the most highly permeable formation zone 14 more diverting agent is also pumped into formation zone 14. As the diverting agent is pumped into formation zone 14 the diverting agent will act to seal the fractures 24 and 24a, including any newly propagated fractures thereby reducing the permeability of the formation zone 14 and causing the fracturing fluid that follows the diverting fluid to flow to next most highly permeable formation zone such as formation zone 16 where the process is repeated until all of the formation zones 12, 14, and 16 have been treated to increase the permeability of all of the formation zones 12, 14, and 16.
Once all of the formation zones 12, 14, and 16 have been treated the formation zones are not initially permeable due to the diverting agent that has been forced into each zone. However, with the presence of the catalyzing agent the diverting agent begins to break down in a few hours. It is generally accepted that upon 80% of the diverting agent degrading, the diverting agent is then able to flow out of the well. Once the diverting has degraded and begins to move out of the fractures and the formation zones the now increased permeability of the formation zones is restored.
While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.
Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.
This invention is a continuation in part application and claims priority to U.S. patent application Ser. No. 14/644,281 that was filed on Mar. 11, 2015.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 14644281 | Mar 2015 | US |
| Child | 15279741 | US |
