Patent Application
20070284106
A more complete understanding of the present inventions and the advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings in which:
The details of the methods and apparatus according to the present inventions will now be described with reference to the accompanying drawings wherein like reference characters are used to indicate like or corresponding parts through the several figures.
In
In the illustrated embodiment of
In
The open-bore wellbore portions 18a (shown in dotted lines in
According to the present inventions one embodiment of the well forming and treatment tool assembly 100 of the present inventions is illustrated in
Well logging is one technique used for measuring and recording rock materials and fluid properties around the wellbore to find hydrocarbon zones in the geological formations below the earth's crust. The prime target of logging is the measurement of various geophysical properties of the subsurface rock formations. Of particular interest is porosity and permeability. A logging procedure consists of moving a ‘logging tool’ through the wellbore (or hole) to measure the rock and fluid properties of the materials surrounding the wellbore. An interpretation of these measurements is then made to locate and quantify potential depth zones containing oil and gas (hydrocarbons). Logging tools measure the electrical, acoustic, radioactive, electromagnetic, and other properties of the rocks and their contained fluids. This data is recorded to a printed record called a ‘Well Log’ which is used with other information to design a well treatment plan. Logging While Drilling (LWD) apparatus, measures geological parameters while the well is being drilled and transmit the data via pressure pulses in the well's mud fluid column. The types of instrumentation deployed and measurements made during well logging is quite broad. Logging measurements include the basic electrical logs (resistivity) and spontaneous potential (SP) logs. Porosity is measured (estimated) via sonic velocity and nuclear measurements. Radiofrequency transmission and coupling techniques are used to determine fluid conductivity. Sonic transmission characteristics (pressure waves) determine mechanical integrity. Nuclear magnetic resonance can determine the properties of the hydrogen atoms in the pores (surface tension, etc.). Nuclear scattering (radiation scattering), spectrometry and absorption measurements can determine density and elemental analysis or composition. High resolution electrical or acoustical imaging logs are used to visualize the formation, compute formation dip, and analyze thinly-bedded and fractured reservoirs.
MWD is a procedure used to transmit measurements about downhole conditions and orientation in real time, without interrupting the drilling operation. MWD tools are typically used to survey the path of a drilled well, as well as orient a downhole bent mud motor (or bent orienting sub) to drill in a desired direction. Another use of MWD is real time acquisition of natural gamma values.
In the preferred embodiment the tubular member 110 comprises coiled tubing extending through the wellhead 12. While coiled tubing is preferred because of its ease of use and low expense other tubular members could be used such as drill pipe and the like.
The jetting tool 120 is mechanically connected to the tubular member 110 by threads or the like and has an axially extending central passage 128 in fluid communication with the member 110. Passage 128 is defined by an inner wall 122. At least one radial jet passage 125 extends from the jetting tool's inner wall 122 to the jetting tool's outer wall 124. Fluid jet nozzles 126 are present on the outer end of passage 125 for forming directional jets of fluid. Fluid jet nozzles 126 may extend beyond the outer wall 124 or the fluid jet nozzles 126 may extend only to the surface of the outer wall 124. In embodiments where fluid jet nozzles 126 extend beyond jetting tool's outer wall 124, the nozzles' orientation may be dependent upon the properties of the materials surrounding the wellbore to be fractured. Fluid jet nozzles 126 have an exterior opening that allows fluid to pass from the passage 128 of jetting tool 120 through passage 125 and through fluid jet nozzles 126 to be directed against the wellbore wall to form perforations therein. Fluid jet nozzles 126 may be composed of any material that is capable of withstanding the stresses associated with fluid fracture and the abrasive nature of the fracturing or other treatment fluid and any proppant or other fracturing agent used. In some jetting tool embodiments, fracturing ports (not shown) can also be provided.
The details of the construction and orientation of a jetting tool example is disclosed in the previously incorporated U.S. Publication 2005/0263284. One of ordinary skill in the art may vary these parameters to achieve the most effective treatment for the particular well.
A circulation tool 130 is connected to the jetting tool 120 and has an axially extending central passage 148 in fluid communication with passage 128. In the illustrated embodiment the circulation tool 130 has a cylindrical body with an inner and outer wall. Extending radially from passage 148 between the circulation tools inner and outer walls is at least one fluid circulation passage 142. For purposes of description the tool 130 is illustrated with four circumferentially spaced longitudinally extending slot shaped passages 142.
As shown in
In the illustrated embodiment, sleeve 140 is designed to move by rotating about a longitudinally extending sleeve axis. By circumferentially spacing the apertures 132 and 134, the sleeve 140 can be rotated so that sets of apertures are aligned or misaligned with one or any combination of passages. Hence, it is possible by controlling the orientation of sleeve 140 to control whether fluid from passage 128 flows through the fluid jet(s), fracturing port(s), or circulation passage(s) or a combination thereof. In one embodiment of the present inventions, it is possible to orient rotating sleeve 140 so as to prevent flow from passage 128 into any one or all of the fluid jets, fracturing ports and circulation passages. It is also envisioned that the sleeve 140 could alternatively be movable axially (or be movable both with rotation and by axial shifting) with axially spaced apertures that shift into and out of alignment with the passages to control flow. It is also envisioned that a plurality of down hole valve units either sleeves or other types could be used to control flow during well treatments instead of the single movable sleeve illustrated.
Sleeve 140 may be positioned in the desired orientation (rotated or shifted) through any number of methods known in the art. One non-limiting example of a device for re-orienting moving sleeve 140 is by connecting sleeve 140 to downhole power unit 150. Downhole power unit 150 may be any suitable downhole power unit, most often battery powered. Downhole power units are well know in the industry and typically consist of a communication means (e.g., conductor, or communicator); power source (e.g., conductor, battery or compressed gas) and an actuation device (e.g., motor, solenoid or hydraulic cylinder) that is used to operate a downhole tool such as a valve. The downhole power unit 150 may be located above, below or between the jet tool and the circulation tool. The downhole power unit 150 preferably is designed so as to allow fluid flow through an axial fluid passage 152.
Where downhole power unit 150 is used as the means to move the sleeve 140 into desired orientation, it may be necessary to communicate between surface equipment and downhole power unit 150 in order to change orientation. Non-limiting examples of such communications means include mud pulse, sonic, or wireline. Thus, commands and data can be sent between the surface equipment and the downhole power unit 150 to allow control the change of orientation of rotating sleeve 140. Other methods of controlling the sleeve position could for example include mechanically rotating or shifting the sleeve from the surface; using pressure variations in the wellbore to rotate the sleeve and the like, or using a wireline tool directly to move the sleeve either axially or radially.
Seat assembly 160 is connected to the lower end of the unit 150 and has an axially extending central passage 162 in fluid communication with passage 152. An upwardly facing valve seat 164 is provided in the passage 162 for receiving a ball 166. The ball 166 is of a size that can be flowed or dropped through the tubular member 110 to move to and engage the valve seat to block flow of fluids from the tubular member 110 through the passage 162.
Drilling assembly 170 is connected to the seat assembly 160. In the illustrated configuration the drilling assembly 170 comprises: a fluid powered motor 172, a drill collar 173, a cutter 174 and a centralizer 180. The cutter 174 is illustrated here as a bit, but it is envisioned that other types of bore forming apparatus could be used instead of a bit and motor combination, such as, devices referred to by different terms including jetting device, cutter, bit, drill, mill and the like.
The methods and apparatuses of the present inventions are used to perform work on open-hole wellbore portions (such as the examples of wellbore portions 18a illustrated as dotted lines in
According to one example embodiment of the methods of the present inventions, in order to design a well treatment plan to be used on hydrocarbon bearing subterranean area 20, a pilot hole 22 is drilled along the wellbore portions 18a. For example, see
In a different embodiment, the tools and technology of measuring while drilling (MWD) and/or logging while drilling (LWD) could be used to measure the properties of the materials (solids and liquids) surrounding the wellbore. In this alternative embodiment, in a single trip into the well the pilot hole is measured and logged while it is drilled. MWD and LWD equipment can be placed in the drill collar 204 or can be in a separate housing. Examples of MWD and LWD processes and equipment are disclosed in U.S. Pat. Nos. 2,810,546; 3,932,836; 3,309,656; 4,254,225; 5,586,084; 6,666,285; 6,850,463; and 6,927,390 which are incorporated herein by reference for all purposes. In the single pilot hole MWD and/or LWD trip data can be obtained for designing a well treatment plan for wellbore portion 18a.
In another embodiment, MWD and/or LWD equipment could be used during forming of the finished wellbore to measure the properties of the materials (solids and liquids) surrounding the wellbore. MWD and/or LWD equipment could be added to the tool assembly 100 so that data from these measurements used to design a well treatment plan for a wellbore portion is collected during drilling of the finished open wellbore portion 18a. These measurements include all conventional measurements made in well logging and pressure and flow testing. As used herein, the term measuring the material around the wellbore is used in its broadest sense to include any measurements and tests that are useful in locating and designing well treatments for the welbore. In situations where a pilot hole is unnecessary both the pilot hole drilling trip and separate logging-measuring trip could be eliminated, as described hereinafter in more detail.
The next step involves, opening up the wellbore portion 18a to a full sized wellbore (See
If the pilot hole trip is eliminated, as previously described, MWD and/or LWD equipment can be included in the drill collar 170 or other portion of the tool assembly 100. The data necessary to design a treatment plan can be collected during drilling and transmitted to the surface without removing the tool assembly 100 from the wellbore. This data may be transmitted by mud pulse, acoustic, laser or electromagnetic telemetry, or for example smart fluids or particles circulated to the surface, or by other methods of downhole to surface communication known to those skilled in the art.
Once drilling is completed and the wellbore portion 18a is opened up to the desired size for production, well treatment can be performed on the portion. The logging data, either from the pilot hole logging, or the MWD and LWD data obtained during the final hole forming can be used to identify the location of the wellbore portions and type of treatment to be applied to the wellbore portions. In the
With the drill motor disabled, wellbore treatments of the wellbore portion 18a may also be accomplished without first removing the tool assembly 100 from the wellbore. The wellbore can be cleaned up by opening passage 142 and pumping cleaning fluids through the well. Formation treatment proceeds as the tool is moved into and out of one or more treatment locations.
For example the tool assembly 100 can be moved to a first location and perforation can be accomplished by moving the sleeve to open up flow into the at least one fluid jet nozzle 126 and blocking flow through the circulation tool 130. As shown in
A variety of fluids can be utilized in accordance with the present inventions for forming fractures, including aqueous fluids, viscosified fluids, oil based fluids, and even certain “non-damaging” drilling fluids known in the art. Various additives can also be included in the fluids utilized such as abrasives, fracture propping agent, e.g., sand or artificial proppants, acid to dissolve subterranean materials and other additives known to those skilled in the art. Conformance fluids which prevent flow from water producing areas or relative permeability modifiers, which reduce water flow from commingled areas may also be injected into the materials surrounding the wellbore.
As is well known the pressure at which the fluid must be jetted from fluid jet nozzles 126 and/or pumped from the annulus to result in the fractures 250 is dependent upon the particular type of rock and/or other materials surrounding the wellbore and other factors known to those skilled in the art. Generally, after a wellbore is drilled, the fracture initiation pressure can be determined based on information gained from testing and logging and during drilling and other known information.
Depending upon the formation treatment plan, a propping agent or other solid may be combined with the fluid being jetted into the material surrounding the wellbore. The propping agent, e.g., sand, resin coated sand or the like functions to prop open the fractures 250 when they attempt to close as a result of the termination of the fracturing process. Some propping agents also stabilize the material surrounding the wellbore and act as a filter to keep undesirable materials from flowing into the wellbore.
While propping agent 260 can be mixed at the surface with the jetting fluid in the preferred embodiment it is pumped down the annulus. As illustrated in
Before moving the tool assembly 100 to a new location additional well treatment processes can be performed such as pumping fluids into the propping agent and material surrounding the wellbore. For example, acids, stabilizers, tackifiers, curable resin, and the like could be pumped. If an uncoated proppant is used a curable resin could be pumped into the proppant to consolidate the proppant pack for proppant flowback control.
Following completion of well treatment at the first location the tool assembly can be moved uphole to a point above the next treatment location or above the excess propping agent 260 in the wellbore. As used herein, uphole refers to the direction along the wellbore toward the wellhead and may include lateral or downward movement as well as vertically upward movement. To eliminate any proppant or other material bridging the well bore, the tool can be washed down to the next treatment location to clear the well bore, as show in
The well treatment process can be completed at the new location as shown in
The multiple well treatment process can be performed in a single trip (without removing the well tool assembly 100 from the well) by moving up the well from treatment location to treatment location and repeating the appropriate processes described above. Once all necessary well treatments are completed the wellbore can be cleaned of propping agent before removing the tool assembly by opening the circulation ports or by a separate cleanout trip using coil tubing. Cleaning can also be accomplished after each zonal treatment by opening the circulation ports and circulating fluid through the string and annulus. As previously mentioned, the wellbore clean out step can be accomplished by using the wellbore forming apparatus either alone or in conjunction with fluid flow. For example, if cured resin coated proppant is present in the wellbore following wellbore treatment, the drilling and treatment assembly can be used to ream out the wellbore without removing the assembly from the wellbore. To accomplish this step, the DPU would be operated to open the valve (or sleeve valve) controlling fluid flow to the drill motor, the drill would be operated and advanced back through the wellbore to ream out the cured resin. This reaming out could be performed with washing fluid flowing from the circulation tool 130 and or fluid nozzles. Indeed, an open bore completion without screens or gravel packing can be achieved in a single trip using these inventions with resin coated proppant and wellbore reamout. Upon completion of the treatment, a production tubing assembly may or may not be placed into the open hole portion of the wellbore. The production tubing assembly may include a slotted or perforated expandable or non-expandable liner, and either non-expandable or expandable screens, expandable, swellable or conventional hydraulic or mechanical force setting packers to isolate portions of the wellbore. Gravel packing may also be considered in portions of the wellbore if necessary to prevent sand production.
Therefore, the present inventions are well-adapted to carry out the objects and attain the ends and advantages mentioned as well as those which are inherent therein. While the invention has been depicted, described, and is defined by reference to exemplary embodiments of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the invention are exemplary only, and are not exhaustive of the scope of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.
