Wells – Processes – Placing or shifting well part
Reexamination Certificate
2001-01-26
2002-12-24
Neuder, William (Department: 3672)
Wells
Processes
Placing or shifting well part
C166S077200
Reexamination Certificate
active
06497290
ABSTRACT:
FIELD OF THE INVENTION
This invention pertains to safeguarded methods and apparatus for providing fluid communication with coiled tubing, useful in communicating fluids within wells, and particularly applicable to drill stem testing and/or operations in sour wells. The invention further pertains to multicentric coiled-in-coiled tubing, useful for safeguarded downhole or conduit operations, and its method of assembly, including preferred and alternate methods. The invention also pertains to the use of coiled-in-coiled tubing with a bottomhole assembly package for operations that may be particularly pertinent to horizontal and/or deviated wells, including operations such as treating or forming or testing or measuring and the like, and in particular, to combinations of the above operations performable in the same run.
BACKGROUND OF INVENTION
This application is related to and comprises a continuation in part of prior pending application having PCT Serial Number PCT/US95/10007. The corresponding U.S. Ser. No. is 08/564/355.
The oil and gas industry uses various methods to test the productivity of wells prior to completing and tying a well into a pipeline or battery. After drilling operations have been completed and a well has been drilled to total depth (“TD”), or prior to reaching TD in the case of multi-zoned discoveries, it is common to perform a drill stem test (“DST”). This test estimates future production of oil or gas and can justify a further expenditure of capital to complete the well.
The decision to “case” a well to a particular depth, known as a “casing point election”, can result in an expenditure in excess of $300,000. Without a DST, a wellsite geologist must make a casing point election based on only core samples, cuttings, well logs, or other indicators of pay thicknesses. In many cases reservoir factors that were not knowable at the time of first penetration of the producing zone, and thus not reflected in the samples, cuttings, etc., can control the ultimate production of a well. A wellsite geologist's problem is exacerbated if the well is exploratory, or a wildcat well, without the benefit of comparative adjacent well information. Further, the geologist must make a casing point election quickly as rig time is charged by the hour.
A DST comprises, thus, a valuable and commonly used method for determining the productivity of a well so that optimal information is available to the geologist to make a casing point election. Traditionally the DST process involves flowing a well through a length of drill pipe reinserted through the static drilling fluid. The bottom of the pipe will attach to a tool or device with openings through which well fluids can enter. This perforated section is placed across an anticipated producing formation and sealed off from the rest of the wellbore with packers, frequently a pair of packers placed both above and below the formation. The packer placement or packing off technique permits an operator to test only an isolated section or cumulative sections. The testing can involve actual production into surface containers or containment of the production fluid in the closed chamber comprised by the pipe, pressure testing, physically retrieving samples of well fluids from the formation level and/or other valuable measurements.
The native pressure in producing reservoirs is controlled during drilling through the use of a carefully weighted fluid, referred to above and commonly called “drilling mud”. The “mud” is continuously circulated during the drilling to remove cuttings and to control the well should a pressurized zone be encountered. The mud is usually circulated down the inside of the drill pipe and up the annulus outside of the pipe and is typically made up using water or oil based liquid. The mud density is controlled through the use of various materials for the purpose of maintaining a desired hydrostatic pressure, usually in excess of the anticipated native reservoir pressure. Polymers and such are typically added to the mud to intentionally create a “filter cake” sheath-like barrier along the wellbore surface in order to staunch loss of over-pressured drilling fluid out into the formation.
As can be easily appreciated, when an upper packer of a DST tool seals an annular area between a test string and a borehole wall, the hydrostatic pressure from the column of drilling fluid is relieved on the wellbore below the packer. The well below the packer, thus, can flow if an open fluid communication channel exists to the surface. At least the well will flow to the extent that native pressure present at the open formation of the isolated section exceeds the hydrostatic head pressure of the tested fluids in the drill pipe. Such produced fluids that flow to or toward the surface are either trapped in the pipe string or collected in a container of known dimensions and/or flared off. By calculating the volume of actual fluid produced, after considering such factors as the time of the test and the size of the choke used, a reasonable estimate of the ultimate potential production capacity of a well can be made. Upon occasion formation pores are too clogged, as by the drilling fluid filter cake, to be overcome by formation pressure and flow. It may be desired in such cases to deliver a gas or an acid to the formation to stimulate flow.
Many wells throughout the world contain hydrogen sulfide gas (H2S), also known as “sour gas”. Hydrogen sulfide gas can be harmful to humans or livestock at very low concentrations in the atmosphere. In Alberta, Canada, sour wells commonly produce hydrocarbon fluids with concentrations of 2-4% H2S and often as high as 30-35% H2S. These are among the most sour wells in the world. It is also known that sour gas can cause embrittlement of steel, such as the steel used in drill pipe. This is especially true when drill pipe contains hardened steel, which is commonly used to increase the life of the drill string. Due to a tendency for drill pipe to become embrittled when exposed to H2S and the possibly disastrous effect of sour gas in the atmosphere with its potential for environmental damage or injury to people or animals, it is extremely uncommon to perform drill stem tests on sour wells. Even a pin hole leak in a drill pipe used for such purposes could have deleterious results.
Unfortunately, many highly productive wells are very sour and found in exploratory areas. In some cases, oil companies have been prepared to go to the expense of temporarily completing a sour well by renting production tubing and hanging it in a well without cementing casing in place, just to effect a production test. This method, due to the increase in rig time, can cost in excess of $200,000, which could be greater than the cost of a completion in shallow wells.
Coiled tubing is now known to be useful for a myriad of oilfield exploration, testing and/or production related operations. The use of coiled tubing began more than two decades ago. In the years that have followed coiled tubing has evolved to meet exacting standards of performance and to become a reliable component in the oil and gas service industry. Coiled tubing is typically manufactured from strips of low alloy mild steel with a precision cut, and rolled and seam welded in a range of OD (outside diameter) sizes, envisioned to run up to 6 inches. Currently, OD sizes are available up to approximately 4 inches. Improvements in manufacturing technology have resulted in increased material strength and consistent material quality. Development of a “strip bias weld” has improved the reliability of factory made joints in the coiled tubing string. Heat treatment and material changes have increased resistance of the tubing to H2S induced embrittlement and stress corrosion cracking that can incur in operations in sour environments. An increase in wall thickness and the development of higher strength alloys are also allowing the industry to increase the depth and pressure limits within which the tubing may be run. The introduction of new materials and structure, such as titanium and composite
Fried Spencer J.
Misselbrook John G.
LandOfFree
Method and apparatus using coiled-in-coiled tubing does not yet have a rating. At this time, there are no reviews or comments for this patent.
If you have personal experience with Method and apparatus using coiled-in-coiled tubing, we encourage you to share that experience with our LandOfFree.com community. Your opinion is very important and Method and apparatus using coiled-in-coiled tubing will most certainly appreciate the feedback.
Profile ID: LFUS-PAI-O-2921469