NO316129B1 - Apparatus and method using coil-in-coil tubes - Google Patents

Description

APPARATUS AND PROCEDURE IN WHICH COIL-IN-COIL PIPE IS USED

This is a partial continuation of PCT US 95/10007, filed 7/25/95, also US serial no. 08/564,355 filed 19.3.96, granted 12.12.96.

The invention relates to safe methods and apparatus for providing a fluid connection with coiled tubing, which is useful for transferring fluids inside wells, and particularly applicable for drill string testing and/or operations in acidic wells. The invention further relates to multicentric coil-in-coil pipes, useful in safe downhole or conduit operations, as well as a method for mounting this, including preferred and alternative methods. The invention also relates to the use of coil-in-coil pipe with a bottom hole string package for operations which may be relevant in particular with horizontal and/or deviated wells, including operations such as treatment, forming, testing or measurement and the like, and in particular combinations of the above operations which can be performed at the same time.

The application relates to and includes a partial continuation of an earlier, pending application which has PCT serial no. PCT/US95/10007. The corresponding US sen no. is 08/564/355.

The oil and gas industry uses various methods to test the productivity of wells before completion and connection of a well to a pipeline or battery. After drilling operations have been completed and a well has been drilled to total depth ("TD"), or before it reaches TD in the case of multi-zone discoveries, it is customary to conduct a drill string test ("DST"). This test estimates future production of oil or gas and can justify further capital expenditure to complete the well.

The decision to "line" a well to a specific depth, known as "lining point selection," can result in an outlay in excess of $300,000 {approx. NOK 2,200,000). Without DST, an on-site geologist must make a casing point selection based only on core samples, cuttings, well logs, or other indicators of production zone thickness. In many cases, reservoir factors that were not known at the time of the first penetration into the production zone, and therefore not reflected in the samples, cuttings, etc., can control the final production in a well. The problem for an on-site geologist is exacerbated if the well is an exploration well or a survey well without the advantage of having comparable information from neighboring wells. Furthermore, the geologist must make a selection of a casing point quickly since time is charged per hour.

A DST thus constitutes a valuable and commonly used method for determining a well's productivity, so that optimal information is available to the geologist to choose f nr-i nnsnnnlrt' TraHieiftnolf *i nnhpf attsr" nST-riT-nKPHfSÉin S la e»n well flow through a length of drill pipe that is re-entered through the static drilling fluid. The bottom of the pipe will be attached to a tool or device with openings through which well fluids can flow in. This perforated section is located across a presumed producing formation and is sealed against the rest of the borehole with packings, often a pair of packings placed both above and below the formation. The placement of the packings or the packing technique allows an operator to test only one isolated section or a collection of sections. The testing may involve actual production to surface reservoirs or to retain the production fluid in the closed chamber formed by the pipe, pressure testing, physical collection of samples of the bridge nnfluids from formation level and/or other valuable measurements.

The natural pressure in producing reservoirs is controlled during drilling using a carefully weighed fluid, discussed above and often called "drilling mud". The "mud" is circulated continuously during drilling to remove cuttings and to have control over the well if a known pressure zone is encountered. The mud is usually circulated down the inside of the drill pipe and up through the annulus outside the pipe and is typically made using water or an oil-based fluid. The density of the mud is controlled using different materials in order to maintain a desired hydrostatic pressure, usually in excess of the expected natural reservoir pressure. Polymers and the like are typically added to the mud to intentionally form a "filter cake<n->jacket-like barrier along the borehole surface to stop loss of overpressured drilling fluid to the formation.

As can be readily appreciated, when a DST tool's upper packing seals an annular area between a test string and the wall of a borehole, the hydrostatic pressure of the drilling fluid column is relieved on the borehole below the packing. The well below the seal can thus flow if there is an open fluid transfer channel to the surface. At least the well will flow to the extent that the natural pressure found in an open formation in the isolated section exceeds the hydrostatic pressure in the tested fluids in the drill pipe. Such produced fluids that flow to or towards the surface are either closed inside the pipe string or collected in a container with known dimensions and/or burned off. By calculating the volume of the actual fluid produced, after considering such factors as test time and the size of the choke used, a reasonable estimate of the final potential production capacity for a well can be made. Occasionally, formation pores are too clogged, as with the drilling fluid filter cake, to be overcome by formation pressure and flow. In such cases, it may be desirable to add a gas or an acid to the formation to stimulate flow.

Many wells around the world contain hydrogen sulphide gas (H2S) also known as "sour gas". Hydrogen sulphide gas can be harmful to humans and domestic animals in very low concentrations in the air. In Alberta, Canada, it is common for sour wells to produce hydrocarbon fluids with concentrations of 2-4% H2S and often as high as 30-35% H2S. These are among the most acidic wells in the world. It is also known that acid gas can cause steel to become brittle, such as the steel used in drill pipes. This is particularly the case when drill pipe contains hardened steel, which is commonly used to increase the life of the drill string. Because of the tendency of drill pipe to become brittle when exposed to H2S, and because of the potentially catastrophic effect of acid gas in the atmosphere with its potential for damage to the environment or to humans and animals, it is highly unusual to conduct drill string tests on acid wells. Even a leak as large as a pinhole in a drill pipe used for such a purpose could have a devastating effect.

Unfortunately, many very productive wells are very acidic and are found in exploration areas. In some cases, oil companies have been willing to go to the expense of temporarily completing a sour well by renting production tubing and hanging it in a well without cementing the casing in place, just to conduct a production test. This method can, due to the increase in rig time, cost in excess of $200,000 (approx. NOK 1,500,000), which can be more than the cost of a completion in shallow wells.

Coiled tubing is now known to be useful for a myriad of exploration, test and/or production related operations in oil fields. The use of coiled pipes began more than twenty years ago. In the years since, coiled tubing has been developed to meet exacting performance standards and to become a reliable component in the oil and gas industry. Coiled tubing is typically manufactured from low-alloy mild steel strip with a precision cut and rolled and seam-welded in a variety of OD (outside diameter) sizes, which are intended to be found up to 6 inches (152 mm). Today, there are OD sizes up to about 4 inches (102 mm). Improvements in manufacturing technology have led to increased material strength and consistent material quality. development of a "band pre-tension weld" has improved the reliability of factory-made joints in the coiled tubing string. Heat treatment and changes in material have increased the pipe's resistance to HZS-caused embrittlement and stress corrosion cracking which can occur during operations in acidic environments. An increase in wall thickness and the development of higher strength alloys also allows the industry to increase the depth and pressure limits at which pipe can be set. The introduction of new materials and new structures, such as tube design in titanium and composite material, is also expected to further expand the area of application for coiled tubes.

Coiled tubing could be particularly valuable in acidic or very acidic wells due to coiled tubing's typically softer steel composition that is not as susceptible to embrittlement caused by hydrogen sulfide. However, another factor inhibits the production of sour gas or the execution of a drill string test in a sour well with coiled tubing. The repeated rolling and unrolling of the coiled pipe causes the pipe walls, which today are made of steel, to deform plastically. Sooner or later, the plastic deformation of the pipe walls will probably cause a rupture. A resulting leak or crack as large as a pinhole could cause emissions.

Oil and gas operations have known the use of concentric pipe strings. Concentric tubing strings provide two non-borehole channels for downhole fluid transfer, typically with one channel, such as the inner channel, used to pump fluid

(liquid or gas or multiphase fluid) down the hole, while a second channel, such as the annular channel formed between the concentric strings, is used to return fluid to the surface. (An additional annulus created between the outer string and the casing or borehole could of course be used for additional fluid transfer). Which channel is used for which function can be a matter of choice of design. Both concentric pipe channels could be used for pumping up or down.

Concentric piping arrangements using coiled tubing, at least in part, have been proposed for use in some new applications. Coiled pipes in themselves have certain advantages over jointed pipes, such as greater speed when guiding in or out of a well, greater flexibility for setting in "live" wells and greater safety by requiring less personnel to be present in very dangerous areas as well as the absence of joints and their inherent risk of leakage.

Patterson mentions in US patent no. 4,744,420 concentric tube where the inner tube element can be coiled tube. This is fed into an outer pipe element after this element is

been lowered into the borehole. At Patterson's does not include

io the outer tube element coil tube. As fig. 8 of Patterson illustrates, the inner tube is secured within the outer tube by wedge-like fasteners or centering units spaced apart, which keep the tube elements generally centered and coaxial. Sudol mentions in US patent no.

is 5,033,545 and Canadian Patent No. 1325969 coaxially arranged endless inner and outer tube strings. Sudol's coaxial assembly can be stored on a reel that can be transported on a truck, and can be inserted into or extracted from a well by a

tube injector. Sudol's description does not mention explicitly

2o how the coaxial pipe strings are kept coaxial, but Sudol shows an understanding of the use of centering devices. US Patent No. 5,086,8422 belonging to Cholet discloses an outer tube column 16 which is inserted into a main tube column comprising

a vertical part and a curved part. An internal pipe column 25 is then lowered inside the outer pipe column. Cholet mentions that the pipe columns can be shaped to be rigid pipes that are screwed together or are of continuous elements that are rolled out from the surface. Cholet does not mention a single pipe assembly which is wound up on a coil, where the assembly itself comprises an inner pipe length and an outer pipe length. All of Cholet's drawings show coaxial concentricity. US Patent No. 5,411,105 to Gray discusses drilling with

coiled tubing where an inner tube is attached to the spool shaft and is extended through the coiled tubing to the drill tool. Gas is fed down through the inner tube to allow underbalanced drilling. Like Sudol, Gray mentions coaxial tube. Furthermore, Gray does not describe any dimensions for the inner tube, or whether the inner tube includes coiled tubes. A natural assumption in Gray's operation would be that the inner tube could comprise a flexible tube of small diameter, which can be introduced by fluid into the coiled tube while it is on the coil, just as a cable today is led into the coiled tube while it is on the coil. The Grif-fiths patent, US No. 5,503,014, issued April 2, 1996, filed July 29, 1994, practices a version of drill string testing using a dual coaxial coil. Nothing is said about test tools or downhole string. Norwegian patent application 980295 specifies equipment and methods for fluid transport and well treatment using a coil-in-coil tubing string with downhole seals

The present invention solves the problem of providing a safe method for transferring potentially hazardous fluids and materials through coiled pipes. This safe method is particularly applicable for the production and testing of fluids from wells, including very acidic gas wells. The safe method suggests the use of coil-in-coil tubing comprising an inner coiled tube length placed inside an outer coiled tube length. Potentially hazardous fluid or material is passed through the inner pipe length. The outer length of pipe provides an additional layer of protection. The outer pipe delimits an annular area between the lengths, which can be pressurized and/or monitored for quick indication of any leakage in one or the other of the pipe lengths. If a leak is discovered, the flow of fluid can be stopped, a well can be killed or shut in, or other measures can be taken before a fluid impermissibly pollutes the environment.

As an additional feature, the annular area between the pipe lengths can be used to circulate fluid down and flush up inside the pipe, to provide stimulating fluid to a formation, to provide lifting fluid to the inner pipe or to provide fluid to inflate packings which is located on a connected downhole device, etc.

The present invention also relates to the assembly of multicentric coil-in-coil pipe, where the proposed structure offers a structure and a method of improved or new design. This improved or new design provides advantages such as efficient, effective assembly, long service life or improved service life, and possibly improved structural strength. A preferred method and alternative methods for mounting multicentric and concentric coil-in-coil are described.

It has been discovered that coil-in-coil tubing can offer the same advantages of flexibility and insertability as found with simple coiled tubing compared to spliced tubing, features that are particularly useful when working in horizontal and/or deviated wells. However, coil-in-coil tubing provides the operator with two conduits as opposed to one for transferring fluids, such as from the surface to the downhole, or from the downhole to the surface, from the surface to tool combinations in a downhole string, and/or to provide an isolation chamber. These lines are of course in addition to the pipe-borehole annulus which can or would be used as a line.

Some operations, as discussed above and below, may benefit from the availability of a secure or isolated product line. Some tools, as mentioned in the above discussion of Sudol and the sand suction tool, prescribe two fluid lines for their operation, and others can benefit from such.

Given the construction of the coil-in-coil pipe prototype, it has since been discovered that well operations such as treatment, forming, test and/or measurement operations and the like, and particularly including combinations of the above, could be carried out cost-effectively with coil-in-coil. For example, the efficiency of testing combined with well improvement operations could be increased if they were carried out at the same time as other operations down the borehole. The flexibility provided by access to multiple lines for pumping down, pumping up, and circulating fluids, and for performing the same simultaneously or in sequence, enables many new combinations of operations that have not previously been possible in one round downhole. Multiple circulation conduits allow combinations of operations to be performed downhole in new, improved and inventive ways. The added efficiency may justify the additional cost of using coil-in-coil, as well as adding a safety factor.

The invention relates to the use of coil-in-coil tubing (several tens of meters of an inner coiled tube of smaller diameter placed inside an outer coiled tube of larger diameter) to provide a safe method of fluid transfer. The invention is particularly useful for well production and testing. The apparatus and the method are of particular practical importance today for drill string testing and other testing or production in potentially acidic or very acidic wells. The invention also relates to an improved design of "multicentric" coil-in-coil pipe and the method for mounting this.

The use of two coiled tubing strings, one arranged inside it

others, they double as mechanical barriers to the outside environment. Fluid in the annulus between the strings can be monitored for leaks. To aid in monitoring, the annular area between the coils can be filled with a mart gas, such as nitrogen, or a fluid such as water, sludge or a combination of these, and pressurized.

In one embodiment, a fluid, such as water or a mart gas, can be placed in the annulus between the tubes and pressurized. This annulus fluid can be put under a higher pressure than either the pressure in the dangerous fluid that is carried via the innermost string, or the pressure in the fluid that surrounds the outer string, such as static drilling fluid. Due to this pressure difference, the fluid in the annulus between the inner and outer strands will flow outwards through the hole should a pin-sized leak or crack develop in one or the other coiled tube strand. Instead of acid gas, for example, potentially leaking out and contaminating the environment, the inner string would be invaded by the annulus fluid and still be contained in a closed system. An annulus manometer on the surface could be used to register a pressure drop in the annulus fluid, which would indicate that there is a leak.

Fluids that are passed through the inner string could, in one embodiment, be left in the closed chamber formed by the inner string, or they could be led separately from the coil-in-coil tube at the spool or work drum. Fluids directed separately could be metered or fed into a flame on the surface or produced into a closed container, in other embodiments.

The coil-in-coil pipe must be connected or attached to a device at its distal end to control flowing fluids

through the inner tube. Fluid transfers through the annular channel must also be checked. At a minimum, these checks could simply include sealing the annular area. During drill string testing, gaskets and sealing techniques could be used in a similar way to standard drill string tests. An additional advantage is provided through the invention in that a downhole packing could be inflated with fluid supplied down through the coil-in-coil pipe.

The inner coil tube is thought to vary in dimension between 12.7mm and 139.7mm outside diameter ("OD"). The outer coil tube can vary between 25.4 mm and 152.4 mm in external diameter. A preferred size is 31.8 to 38.1 mm OD for the inner tube and 50.8 to 60.3 mm OD for the outer tube.

It is known that steel with a hardness of less than 22 on the Rockwell C hardness scale is suitable for use with acid gas. Coiled pipe can usually be produced with a hardness of less than 22 since it does not need to have the strength required for standard drill pipe. Coiled tubing is thus particularly suitable for use with acid gas, including drill string testing as discussed. Other materials such as titanium, corrosion resistant alloy (CRA) or fiber and resin composite could be used for coil tubes. Alternatively, other metals or elements could be added to coiled tubing during its manufacture to increase its lifetime and/or usability.

The invention further includes apparatus and methods for use in downhole well operations such as treatment, forming, testing or measuring and the like, and particularly in combinations of the above. Treatment operations generally refer to operations such as acid treatment or fracturing or heating or other well stimulating activities, including mixing of chemical and biological additives. Treatment may more specifically apply to operations such as a polymer entrapment to shut off suspected water-producing zones, clay swelling control mechanisms, sand control mechanisms, filter cake removal systems, iron or sludge control and fines migration control. Treatment may also involve the addition of one or more of the following, either separately or in combination: emulsifiers, thickeners, polymers, surfactants, buffers, neutralizing agents, rust control agents, inhibitors, diverting agents, breaking agents, cements, additives for fluid loss control, detergents, cleaners, solvents, separating agents, suspending agents, gels or starches, foams or defoamers, gases, friction reducing agents, retarders, lost circulation material, flushing agents or pre-flushing agents, wax or paraffin removers, asphaltene control agents, viscosifiers , dispersants, binders, cement additives and scale inhibitors. In general, treatment fluids can relate to any combination of acid and/or fracturing fluids as well as additions to these. Treatment fluids could be mixed and used simultaneously or in sequence depending on the need for the particular formation. Treatment operations could include high-pressure flushing and sand suction operations.

Forming operations include operations such as drilling, modifying, perfing (perforating), creating build-up sections and shaping wellbore knees, as well as other activities that affect the structure and uniformity of the wellbore. Test operations include production operations, including both production testing and long-term production. A universal tool can be called a production/test tool.

There could be an overlap between test tools and measurement tools. Measuring tools include the spectrum of logging tools as well as pressure measuring devices, flow meters, density sensors, location tools, sampling tools and tools for performing chemical analysis or geological and geophysical analysis downhole.

Apparatus for use in well operations in accordance with the present invention comprises coil-in-coil tubing having an inner coiled tubing length contained within an outer coiled tubing length. The two pipe lengths define a first inner coil fluid line and a second "ring-shaped" fluid line between the coils. The apparatus comprises a downhole string pack adapted to be attached to a portion of the coil-in-coil pipe, typically being attached to the distal end of the coil-in-coil pipe and in fluid communication with both fluid lines bounded by the coil-in-coil- the pipe.

The apparatus may include at least one packing adapted to be connected to the downhole string or pipe. Typically, the packing would be associated with the downhole string and could contain an area packing. The gasket can optionally be given a structure that will allow the pipe to move back and forth or slide while the gasket seals off between a portion of the borehole wall and the pipe.

A gasket emergency inflation mechanism could be included in case of loss of communication. The mechanism could operate through the application of pressure to a locking pin or a number of pins or by any number of other methods that would allow fluid to escape the packings to the wellbore or to the coiled tubing.

In most applications, a surface control mechanism will control fluid transfer within both the inner conduit and the annulus of the coil-in-coil tube. On the surface, the coil-in-coil pipe will preferably be connected to a coil or drum at its proximal end. The current from both wires could be separated by an adaptation mechanism at the coil or drum to channel or control each current separately, as desired.

A bottom hole string package can be anything from elaborate to simple. A drill string test tool as shown in fig. 5 and 5A, comprises a downhole string package. The tool is designed so that it can act as a production/test tool and a processing injection tool. Valves in the tool control the fluid connection between the inner and annular conduits and the borehole as well as between the conduits themselves. Alternatively, a downhole string may comprise one or more of a production/test tool, a pumping tool, a processing injection tool, a vacuum tool, a flushing tool, a perforating tool, a drilling tool, an orientation tool, a hydraulic motor and/or an electric motor. A treatment injection tool could inject treatment fluid. The downhole string could include a variable distance unit. Such devices could ensure distance maintenance from one to fifty metres.

Tools available today, as specified in the list above, would likely need adaptation to work effectively with coil-in-coil tubing in a downhole string package. Some tools, such as a Sudol sand suction tool, or a drill string test tool as in fig. 5, is adapted to work with coil-in-coil pipes. Adapting other tools to operate in a downhole string package coupled to coil-in-coil tubing may require only a suitable adapter to connect the tool's fluid transfer ports to the fluid transfer capabilities of the coil-in-coil tubing, or to the tool sections above . If multiple tools are packed together in a downhole string, some measures will probably need to be taken to align the tool's own fluid transfer ports with the fluid transfer ports of the above tool as well as to direct fluid transfer through or around the tool to serve tools connected below. Such technical and design parameters can be worked out as preferred bottom hole string packages are developed. The greater the commercial market for a particular tool pack string, the greater the likelihood that fluid transfer channels will be incorporated into the tool body itself as opposed to being provided for the occasion or temporarily.

It is envisaged that pumps associated with a bottom hole string may include jet pumps, chamber lift pumps and/or electric pumps. Such pumps will be able to act as alternative systems for extracting flowing well material to the surface for measurement or analysis. Electric submersible pumps are known. A cable will likely extend through one of the two coil-in-coil conduits to provide electrical connection between the surface and the downhole string package. The electrical connection could serve the functions of both power and communication, as illustrated and discussed in US Patent No. 4,898,236 to Sask, entitled "Drill Stem Testing System". The important role of real-time data is discussed in the Sask patent. The cable could include a conductor inside a braided cord, fiber optic cables are also a possibility. If the cable is to be contained within the annular conduit of the coil-in-coil conduit, as opposed to the inner conduit, the coil-in-coil conduit is likely to be concentric as opposed to multicentric. Any single or multi-wire conductor inside a braided cord or smaller coiled tube could function as a communication cable.

A number of different measurement tools can be successfully included in a downhole string package. It would be advantageous to provide more pressure, temperature, log measurements and others.

The apparatus for use in well operations may omit a gasket associated with the pipe and/or downhole string, as the downhole string package may include several tools and functions that have no need to be sealed with gasket. When a packing is included in the downhole string, one line in the coil-in-coil pipe can advantageously be used to set the packing hydraulically. Inflatable/deflate layer packs can be suitable for many operations.

The availability of the above apparatus, namely coil-in-coil tubing and a suitable downhole string package, makes it possible to perform a variety of new, efficient and cost-effective downhole well operations that can be completed in one go. For such operations, the coil-in-coil tubing must be connected to the downhole string package so that both the inner and the annular fluid conduits are in fluid communication with the string.

The bottom hole string must be located at the bottom of a borehole. The easiest is for the string to be injected down the borehole as it is attached to the distal end of the coil-in-coil pipe which is injected from a spool. An advantageous mode of use of the above apparatus includes sealing with a gasket between a portion of the borehole and a portion of the pipe and/or string and pumping fluid down through at least one of the two coil-in-coil pipelines for operations. Fluid, for example, could be pumped down to set the gasket. Fluid pumped down through the line could also be advantageously used to drive tools and to circulate into the borehole. Borehole fluid could be produced up through a line, simultaneously or in sequence with pumping down to facilitate flushing operations.

For example, if a production/test and processing injection combination tool such as that in FIG. 5 and 5A

were to constitute the downhole string together with a packing, the methodology could include first placing the packing in the middle of the drilling fluid in a wellbore using water in a first conduit, preferably the annular conduit. The first line could then be shut off, and borehole fluid below the packing could be produced up through the second line, preferably the inner line. The drilling fluid or mud remains in the annulus between the borehole and pipe above the packing. In the present example, subsequent operation will not contaminate or otherwise destroy the value of this drilling fluid by circulating foreign materials through it.

If testing of the produced fluid indicates that a well treatment could improve production, valves can be opened that allow circulation between the first line and the second line. Water in the first line and production fluid in the second line (and in the borehole below the packing to some extent) can be circulated out, and a treatment fluid, such as acid, can be pumped down. When the fluids have been suitably flushed, the second line can be closed, and the treatment fluid, such as acid, can be injected into the borehole below the packing through the first line. The treatment fluid can be followed by water. Both lines can then be closed while the chemical works. Production can be restored upwards in the second line again, whereby any residual fluids in the line, spent acid and then formation fluid will be produced first.

It can be assumed that the acid injected into the first line was followed by water, so that when the acid treatment is complete, water will remain trapped in the first line. The formation fluid can advantageously be retested. If the test results for the produced formation fluid are now satisfactory, the packing can be emptied, in particular by means of a line for depressurizing the packing chamber, and the process can be repeated elsewhere. If the test results are not satisfactory, the flushing and treatment cycle can be repeated by using the same or different treatment fluids. Area gaskets can be used instead of a single gasket to suitably isolate a production zone.

If testing indicates that a zone is producing water, a polymeric containment chemical can be supplied through one line, such as the first line, to shut off the zone from production. The success or effectiveness of the polymer entrapment will be able to be tested immediately afterwards during production with the tool. In the above sequence of operations, the drilling fluid in the well above the packing has not been contaminated by the need to flush any fluids through the borehole casing above the packing.

A gasket can be placed down the borehole to allow the coil-in-coil pipe to slide back and forth while the gasket seals between the borehole and the pipe wall. Some treatment operations such as sandblasting and/or high-pressure washing require movement of a tool during the operation. Drilling also depends on movement of the coiled tubing inside the borehole. A packing that allows pipe to move back and forth through it, set at a given section, could, for example, allow a horizontal well to be overbalanced in its vertical section, having drilling fluid above the packing, and underbalanced in its horizontal section below the gasket. Gas could be pumped down through one of the two lines with liquid down through the other, both to the bit, to drill under variably balanced conditions while providing adequate cooling and lift to the bit and at the same time a line carrying only liquid for acoustic communication and hydraulic fluid.

By one methodology, with or without packing, fluid could be pumped

down through both lines to a downhole string where each fluid comprises either a hydraulic drive fluid or a well treatment fluid. This methodology would enable the mixing of chemicals down the hole. For example, a first and a second chemical could be more advantageously pumped unmixed, such as fracturing fluid and gel setting chemicals and/or gel breaking chemicals, or such as two different acids. It is sometimes advantageous to have two different treatment fluids that are not mixed until they are ready for use. Heat can be generated more safely down the hole by mixing the two chemicals there. Combustion down the hole can be controlled by a controlled supply of oxygen. Two different tools could be driven hydraulically, where each has its own independent hydraulic pressure and flow rate controlled on

the surface, such as a hydraulically driven drill bit and a hydraulically driven orienting tool, or a hydraulically driven drill bit and a hydraulic high pressure flushing tool. One line could contain hydraulic fluid for operating a rotating cleaning jet, while the other line contained a fluid such as an acid fluid for selective discharge through the rotating jets. Hydraulic fluid down through one line could drive a pump while a treatment or flushing fluid could be supplied through the other line. In one embodiment, a rotary high-pressure flushing tool could be operated in conjunction with a sandblasting tool. Many such tools could be computer-controlled via real-time feedback data.

With another methodology, the outer line could be used to provide heat insulation for fluid in the inner line. For example, viscous oil could be produced through the inner conduit while heat insulation could be provided by a fluid such as a gas, air, a gel or other insulating material in the outer conduit. For the purposes of this description, a vacuum shall be considered a "gas" fluid, as it constitutes a limiting condition for the presence of a gas. Such insulating fluid could keep the oil temperature up and thus the oil viscosity down, so that the oil could be more easily brought to the surface.

One use of the present invention includes a methodology where the downhole string comprises at least a pair of valve-containing production/processing tools separated from each other by a downhole string spacer. Borehole fluid could be produced from two different locations, each up a separate line. The design could be operated with or without gaskets. The two production tools could advantageously be separated by a gasket to test alternative production zones.

A computer system on the surface could advantageously be used to acquire and analyze data in real time to calculate reservoir parameters. The same surface data system could be used to control all downhole tool valves for the movement of all fluids and gases. The apparatus and method advantageously include the possibility of remote data transmission from the well location to another location.

The present invention also includes optimal methods for assembling coil-in-coil pipes. These methods include extending a first length of coiled pipe substantially horizontally. A second inner coil tube length could then be pumped through the first coil tube length and/or pulled through the first coil tube length using a cable and/or injected through the first coil tube length using a coil tube injector. Any combination of pumping, pulling, and mizing, along with lubrication between the coils, could be used simultaneously or in sequence to accomplish the assembly of coil-in-coil tubing.

A better understanding of the present invention can be achieved when the following detailed description of the preferred embodiment is considered together with the following drawings, where: Fig. 1 illustrates typical equipment used for injecting coiled tubing into a well. Figs. 2A, 2B and 2C illustrate a coiled pipe working drum with piping and fittings capable of supporting an inner coil with an outer coil. Fig. 3 illustrates in cross-section an embodiment for separating or separating an inner and outer fluid guide channel in fluid guide channels next to each other. Fig. 4 illustrates in cross-section an inner and an outer coiled tube section with a cable inside. Figures 5 and 5A illustrate one embodiment of a downhole device or tool, adapted to be coupled to coil-in-coil tubing and useful for controlling fluid flow between a wellbore and an inner coiled tubing string as well as between the wellbore and an annular area between inner and outer coiled tubing strings, and also useful in controlling fluid flow between the inner coiled tubing string and the annular region. Fig. 6 illustrates the spiral winding of an inner coil inside an outer coil in "multicentric" coil-in-coil pipe. Fig. 7 illustrates an injection technique for injecting an inner coil inside an outer coil to provide "multicentric" coil-in-coil tubing. Fig. 8 illustrates a method for mounting "multicentric" coil-in-coil pipe. Fig. 9 illustrates coil-in-coil pipes which have cable inside the inner pipe and the inner pipe spirally twisted inside the outer pipe. Fig. 10 illustrates coil-in-coil tubing having an inner tube centered within an outer tube, and having a cable extending in the annulus between the inner and outer tubes.

Fig. 11 schematically illustrates a bottom hole string package.

Fig. 12 illustrates a bottom hole string that includes a string unit where a packing could be carried. Fig. 13 illustrates coil-in-coil pipe attached to a downhole string placed down a borehole, as it has a seal that seals the borehole cavity at the section in question and allows for back and forth movement of the pipe inside the seal. Fig. 14 illustrates a horizontal mounting method for coil-in-coil pipes. Fig. 15 illustrates the use of data control with coil-in-coil tubing and a bottom hole string. Fig. 1 illustrates a typical setup for setting coiled pipes. This set-up is generally known in the field. In this setup, a truck 12 carries behind its wheelhouse a power supply unit including connection to the truck engine or power take-off, a hydraulic pump and an air compressor. The coiled pipe injection operation can be run from a cab 16 located at the back of the truck 12. The cab 16 comprises the operations center. A working drum 14 constitutes the coil which

carries the coiled pipe at the workplace. The coil or drum 14 must be limited in its outside or drum or coil diameter, so that with a full load of coiled tubing wound up on

the coil, the coil can be transported by truck on country roads and to a work site. A typical drum can have a drum diameter of 3 m. The drum 14 contains, as explained in more detail in fig. 2 and 3, fixtures and piping and cables which must allow and/or control connection between coil-

the interior of the pipe string and other instruments or tools or containers placed on the surface. Fig. 1 illustrates a coiled pipe 20 injected over a gooseneck guide 22 by means of an injector 24 and into a casing 32 on the surface. The injector 24 typically includes two hydraulic motors and two counter-rotating chains, by means of which the injector grips the pipe and rolls the pipe mn on or off the spool. A stripper 26 seals between the coil pipe 20 and the borehole. The well is illustrated as having a typical valve tree 30 and a blowout preventer 28. A crane truck 34 provides lifting means for work at the well site. Fig. 2A, 2B and 2C respectively illustrate a side view and a sectional plan view of a work drum 14 equipped for operation with coil-in-coil pipes. Fig. 2A shows a first side view of the work drum 14. This side view illustrates in particular the pipe arrangement provided for the coil to be able to handle fluid communication as well as

electrical communication through the inner coil tube. The inner tube is the tube which is intended to carry the fluid whose transfer is to be ensured, fluid which can be dangerous. The coil-in-coil pipe is connected to the work drum 14 through a rotary coupling 44 and transition 45. Sides of the coupling 44 and the transition 45 are illustrated in more detail in fig. 3. This piping connection provides a side conduit 62 to conduct fluid from the annular area between the two pipe lengths. The fluid transfer through the side line 62 continues through a central part of the drum 14 and a swivel on the other side of the working drum 14. These connections are illustrated in more detail in fig. 2B and 2C discussed below. Fluid from within the inner coil tube as well as a cable 66 is connected through a

transition piece 45 in the split high pressure channel and mn in a high pressure pipe 46. The transition piece 45 in the high pressure channel as well as the high pressure piping 46 is suitable for H2S operation and rotates with the drum 14. The side line 62 also rotates with the coil 14. Wire telemetry cable 66 which is connected to operate downhole tools and provide real-time monitoring, control and data collection, passes out of the high-pressure pipe 46 at a connector 47. The telemetry cable 66, which may be multi-stranded, is connected to a cable swivel connector 42 in a manner known in the art.

A swivel joint 50 provides fluid communication between the non-rotating high-pressure piping and fitting connected to the shaft in the working drum 14 and the rotating high-pressure piping attached to the rotating parts of the drum, which in turn are attached to the coiled pipe on the drum. A high pressure line 52 is connected to the swivel 50 and comprises a non-rotating pipe connection for fluid communication with the inner coil pipe. Valves can be provided in the rotating and/or non-rotating lines as desired or as appropriate. The line 52 can lead to test or collection equipment on the surface in connection with fluid transferred through the inner coiled tube.

Fig. 2B shows a side view of the other side of the work drum 14 in relation to that shown in fig. 2A. Fig. 2B illustrates a pipe arrangement that can be used in the annular area between the coil-in-coil pipe's two coils. A line 58 comprises a

rotating tube connected to the other side of the drum 14 and a conduit 61 which provides fluid flow through a central portion 60 of the coil. The wire or tube 58 rotates with the coil. A swivel 54 connects the non-rotating tube section 56 with the rotating tube 58 and provides fluid

bond with the annular area for the fixed pipe/line 56 on the surface. The pipe 56 can be provided with suitable valves for controlling the connection from the annular area between the two coiled pipe strings and for suitable surface equipment. Such surface equipment could comprise a fluid or pressurized fluid source 76, shown schematically. Such fluid

could include gas, such as nitrogen, or water or drilling mud or some combination thereof. Monitoring means 78, also illustrated schematically, may be provided to monitor fluid within the annular region between the

inner and outer coiled tubes. Monitoring means 78 will be able to monitor the composition and/or pressure of such fluid in the annular area, for example.

Fig. 2C illustrates a sectional plan view of a work drum 14. Fig. 2C illustrates the coil diameter 74 of the work drum 14. A coil surface 75 comprises the surface on which the coil-in-coil tube is wound up. The surface 75 is the surface from which the pipe is rolled out, and on which it is again rolled in. Fig. 2C illustrates a cable connector 42 which forms a connection to the cable 66, and from which an electrical wire 67 is shown to emerge. The cable 66 and the electric wire 67 can be assembled multi-wire wires. The dashed line 72 illustrates the axial center line of the work drum 14, the axis about which the work drum 14 rotates. Right side of fig. 2C illustrates the rotating conduit 58 and the non-rotating conduit 56, both of which are shown in FIG. 2B. They grieve

for fluid formation on the surface with the annular area between the coiled tube strings. The line 61 has a connection through the channel 60 in the work drum 14 to connect the line 58 to the side line 62 on the other side of the work drum 14. The line 61 and the channel 60 rotate with the rotation of the drum itself in the work drum 14. Left side of fig. 2C il-

lustres the rotating tube 46 and the non-rotating tube/line 52. As discussed in connection with fig. 2A, these pipe or conduit sections provide fluid communication between the inner coiled tubing string and surface equipment, if desired.

The transition piece 45 with split channel which provides the side line 62/ is illustrated in more detail in 1 cross section in fig. 3. The cable 66 is shown as it runs into the transition piece 45 from the left side and comes out on the right side into a fluid transfer channel 83. The channel 83 is in connection with the interior of the inner tube string. A bushing 49 anchors an inner tube 102 to the pipe transition piece 45. Gasket and sealant 51 prevents connection between the annular area 80 defined between an outer tube 100 and the inner tube 102 and the fluid guide channel 83. A transition piece 44 anchors the outer coiled tube 100 to the transition piece 45. Fig. 4 illustrates 1 section components 1 coil-in-coil pipe. Fig. 4 illustrates the wire or cable 66 contained in the inner tube 102 again contained in the outer tube 100. The cable 66 could comprise fiber optic cable for some applications. A line 82 denotes the channel for fluid communication inside the inner tube 102. The annular region 80 denotes an annular region between the tubes, which provides for fluid communication between the inner tube 102 and the outer tube 100 if desired. A typical wall thickness for the inner tube 102 is 2.4 mm. A typical wall thickness for the outer tube 100 is 3.2 mm. Fig. 5 schematically illustrates an embodiment of a downhole tool which can be used with coil-in-coil pipe, and which is particularly useful for drill string testing. Tool or device 112 is connected to the outside of the outer tube 100 by means of a sliding coupling 116. The tool 112 is shown located in an area 106 delimited by a borehole 120 in a formation 104. Gaskets 108 and 110 are shown as they close off between the tool 112 and the borehole 120 in the formation 104. If the formation 104 is capable of producing fluid, these will be produced through the borehole 120 in the zone defined between the upper packing 110 and the lower packing 108. The rounded tool end 118 lies below the lower packing 108.

An indicated area 122 in the tool 112 denotes a general gasket and tool spacer area that is typically included in a device 112. Spacers are added to adjust the length of the tool. Measures can be taken in this space, as is known in the art, to collect samples to be retrieved on the surface. An indicated area 124 in the tool 112 denotes a general electronics section typically included in a device 112. An anchor 114 anchors the inner coiled tube 102 inside the outer coiled tube 100 at the device 112 while still providing means for fluid communication between the annular region 80 between the two tube lengths and parts of the tool 112.

Valves provided by the tool are indicated stylized in fig. 5. A valve 130 acts as a circulation valve that allows circulation between the annular region 80 between the coils and the fluid transfer conduit 82 within the inner coil tube 102. The valve 130 could be used to circulate fluid down through the annular region 80 and up through the inner conduit 82 or vice versa. The cable 66 would typically terminate in a cable end coupling, illustrated as a coupling 69 in the tool 112. A valve 132 denotes a valve to allow fluid communication between the inner conduit 82 and the borehole above the upper packing 110. A valve 134 allows well fluids from the formation 104 inside in the annular area 106 of the borehole to flow into the downhole tool 112 between the upper packing 110 and the lower packing 108 and from there into the pipeline 82. A valve 136 denotes an equalizing valve which is typically provided with a tool 112. A valve 131 provides for the inflation of the packings 110 and 108 with fluid from the annular regions 80. A valve 133 is available for injection of fluids from the annular region 80 into the formation, for purposes such as stimulating the formation 104. A connection 105 between the pipe and downhole work -the cloth could contain an associated emergency release mechanism 103, as is known in the art. A valve 138 ensures emptying of the seals 108 and 110.

Fig. 6 illustrates a spirally wound inner coil 102 inside an outer coil 100, which form a "multicentric" coil-in-coil pipe 21, shown stretched in the well 120 through the formation 104. It is believed that when suspended in a vertical well, a coiled tube, such as the outer coil 100, would not hang quite straight. However, the weight of the coil would ensure that it

outer coil 100 hung almost straight. A cover 150 is shown attached to the distal end of the outer coil 100, down the borehole in the well 120. The inner coil 102 is illustrated spirally twisted inside the outer coil 100. This spirally twisting produces a lack of concentricity, or coaxiality, and is intentional. The intentional spiral twist gives a polycentricity to the pipes as opposed to concentricity or coaxiality. The spiral twist can be carried out between an inner coil 102 and an outer coil 100 and will probably not always take the same direction. That is, the spiral twist can alternate between clockwise and counter-clockwise direction. The inner coil 102 is illustrated in FIG. 6 such that it has its weight resting on the bottom cover 150 which is attached to the outer coil 100. In this way, the weight of the inner coil 102 is carried by the outer coil 100, il-

lustrated as being suspended from a coil tube mektor mechanism 24. Alternatively, the weight of the inner coil 102 could be taken down on the bottom of the well 120, or the cover 150 could sit on the bottom of the well 120, whereby the outer coil 100 would be relieved from carrying the weight of the inner coil 102. Fig. 7 illustrates the inner coil tube 102 rolled out from the coil 152 via the gooseneck 154 and through the injector 156 for the inner coil tube and into the outer coil tube 100. The outer coil tube 100 is illustrated suspended after the coil tube injector 24 and down into the well 120 in the formation 104. Fig. 8A through fig. 8F illustrates a method for mounting the multi-core coiled tube 21 on the drum 14, as illustrated in fig. 8G. Fig. 8A illustrates the coil 152 which holds the inner coil tube 102 and is located at the well 120. Together with the coil 152 is the injector 156 for the inner coil tube and the gooseneck support 154 for the inner coil tube. At the well site 120 there is also a coil 158 for the outer coiled pipe, an injector 162 for the outer coiled pipe and a gooseneck 160 for the outer coiled pipe. Fig. 8B illustrates the outer coil 100 as it is injected by the outer coil injector 162 into the well 120 from the coil 158, and as it passes the gooseneck 160. Fig. 8C illustrates the outer coil tube 100 suspended after the outer coil injector 162 above the well 120. The gooseneck 160 and the coil 158 have been removed.

The outer coiled tube 100 is shown as having the cover 150 attached to its distal or downhole end. Fig. 8D illustrates the inner coil tube 102, injected and spirally twisted mn in the outer coil 100 suspended in a well 120. The inner coil 102 is injected from the coil 152 over the gooseneck 154 and via the injector 156. The bottom of the inner coil 102 is shown resting on the cover 150 at the outer coil 100 enclosing, suspended in the well 120 after the injector 162 for the outer coil tube. Fig. 8E illustrates the inner coil 102 which is allowed to slacken and sink, to spiral and twist further, inside the outer coil tube 100 suspended after the injector 162 in the well 120. Fig. 8F illustrates the rewinding of the coil-in-coil tube 21 on the working drum 14 using the injector 162 for outer coil tubes and the gooseneck 160 for outer coil tubes. The outer tube 100 has been connected to the drum 14. If separate means for suspending the outer tube 100 are provided, the operation can be performed with one coiled tube injector and one gooseneck.

In operation, the safe method according to the present invention is carried out for transferring fluid from within a well with coiled tubing carried on a coil. The method is carried out by connecting a remote end of coil-in-coil pipe from a coil to a device that will control fluid transfer. The device, a special tool for the purpose, will be guided into a well. (The safe method of fluid transfer would of course also be effective on the surface. Safe transfer from within a well presents the problem that is difficult to solve.)

Coil-in-coil pipe comprises a first length of coiled pipe placed inside a second length of coiled pipe. A first channel for fluid transfer is defined by the inner pipe length. The device or tool attached to the distal end of the coil-in-coil tube controls fluid transfer through this first internal transfer channel. The device can also control some fluid transfer possibilities also through an annular area. An annular region is defined between the first inner coil tube length and the second outer coil tube length. Fluid transfer must also be controlled, at least to a limited extent, within this annular area. At the very least, such control shall extend to the sealing of the annular area to provide a safety margin in the event of leaks in the inner coil tube. Preferably, such control would include an opportunity to monitor fluid status, such as fluid composition and/or fluid pressure, within such an area with respect to leakage. Preferably, such control would include the ability to pressurize a selected fluid within the annular area to detect leaks more quickly. In preferred embodiments, the annular area can also function as a second fluid transfer channel.

The coil-in-coil pipe is injected from a coil into the well. Primary fluid is passed through the inner pipe length from

the well of the coil. Of course, fluid will also be able to be conveyed in a safe manner from the coil to the well, should this become necessary. The primary fluid may remain contained within the inner tube length as in a closed chamber to minimize hazard. Alternatively, the fluid can be led from the inner pipe length through a swivel placed on the coil to other equipment and/or containers on the surface. The coil-in-coil tube is finally wound back on.

Device for controlling fluid transfer through the inner pipe length usually comprises a special tool developed for several purposes, suitable for working with coil-in-coil pipe. The tool can communicate electronically via a cable, probably multi-wire, routed through the inner tube. The tool can also collect one or more samples of fluid and physically bring the samples to the surface by mnspooling. The tool can also contain means for measuring pressure.

The annular region between the inner and outer coiled tubes provides the safety, the secondary protective barrier, in case of leaks in the inner tube, in the present method of fluid transfer. For that reason, as mentioned 5 above, fluid in the annular area must at least be controlled in the sense that control includes sealing off the annular area. As discussed above, the control preferably includes monitoring of fluid status within the annular area,

such as fluid composition and/or fluid pressure, and may mn-10 include supplying pressurized fluid to the annular region, such as pressurized water, inert gas or nitrogen, drilling mud, or any combination thereof. The pressure in such monitoring fluid can be monitored to indicate leaks in each coil tube's respective wall. Pressurizing the annular region would ensure that a leak in either the inner tube wall or the outer tube wall would cause interstitial fluid to leave the annular region and flow into the inner tube string or to the outside of the coil. - the coil tube. Such overpressurization ensures in particular that potentially dangerous fluid from within the inner tube ever flows into the annular area.

If a leak is indicated in one or the other of the coil pipe walls, the primary fluid transfer in the inner pipe will be able to

is stopped. The well can also be shut in by closing the valve, 25 and/or the well can be killed by emptying the packings. A blow-out protection (BOP) could be activated if necessary.

The present safe method for fluid transfer is applicable when working inside a borehole as well as in a well

well or well pipe. Such borehole, executed well or

30 well pipe can itself be filled with fluid, such as static drilling fluid.

The device or tool for controlling fluid transfer from the well often includes a gasket or gaskets for isolating a zone of interest. The annular area between the tube walls can be used as a fluid transfer channel for the supply of fluid to inflate the seals. The annular area could also be used as a fluid transfer channel for supplying a stimulating fluid, such as acid, or a lifting fluid such as nitrogen, down into the borehole of the well.

The coil-in-coil pipe is attached on the surface to a working drum or coil. The coil for the coil-in-coil tube will contain means for dividing the fluid guide channel originally from within the inner coil tube from the potential transfer channel delimited by the annular area between the coil tube lengths. On the whole, the inner length should also not be more than 1% longer than the outer length.

One aspect of the present invention provides improved apparatus for carrying out the above method, wherein the improved apparatus comprises "multicentric" coil-in-coil tubing. Such multicentric coil-in-coil pipe includes several tens of meters of continuous settable pipe, coiled up on a coil that can be transported on a truck. The pipe includes a first length of coiled pipe with an outer diameter of at least 12.7 mm spirally twisted inside a second length of coiled pipe. Taking into account possible variations between inner and outer tube OD and wall thickness, the first inner length measured in common extent will generally be at least 0.01% longer than the second outer length. On the whole, the inner length should also not be more than 1% longer than the outer length. (It is of course clear that either the inner length or the outer length will be able to extend past the other either at the coil end or at the downhole end. "Measured in common extent" is used to indicate that such extent of one length over the other in each end is not intended to be taken into account when comparing lengths.)

When coil-in-coil tubes are coiled in, the inner length, to the extent that it overcomes friction, will probably tend to be coiled with the largest possible coil diameter. That is, the inner length will tend to coil against the outer inner surface of the outer length. Such a tendency, if achieved, will lead to a significantly greater length for the inner tube in contrast to the outer tube. The difference in length is important because the present inventors anticipate that if the coil-in-coil tubes were allowed to occupy this maximum coil diameter position on the coil and the ends were attached to each other, the inner tube would then be prone to failure or buckling when straightened bay inside the outer tube.

"Concentric" or "coaxial" pipe obviously includes strings of the same length. Centering units could be used to hold an inner tube concentrically or coaxially inside an outer tube on a coil. Alternatively, an inner tube could be inserted coaxially in the straightened state inside an outer tube,

and the two ends of the two tubes could then be fastened together to prevent retraction of the inner tube inside the outer tube during flushing. For example, an inner coiled tubing could be injected into an outer coiled tubing suspended in a vertical well, possibly by

use of means to minimize friction between them, so that measured in common extent the lengths of both coils will tend to hang straight and very nearly have the same length. The inner coil would not become spirally twisted inside the outer coil. To help straighten out any unwanted spiral twist, the inner coil could be snapped onto a cover attached to

bottom of the suspended outer coil. The weight of the outer coil would then be able to be picked up and carried by the inner coil if the inner coil was lifted after snapping onto the end cover. Such lifting of the inner coil bearing not only its own weight but some or all of the weight of the outer coil would help straighten the inner coil within the outer coil and align the two coils. This solution, "coaxial" or "concentric" coils, is considered not to be optimal. Coaxiality could result in an unacceptable level of compression and/or tension being applied to portions of one and/or the other length while resting on the coil.

It is proposed by the present inventors that the "multicentric" coil-in-coil tube described herein best solves the above problems without entailing the complexity of centering units. Spiraling the inner coil inside the outer coil provides an advantageous amount of frictional contact between the two coils, frictional contact that is relatively evenly distributed. Furthermore, the inner coil has a certain amount of flexibility whereby it can regulate its design in the longitudinal direction when winding in and out. The spirally twisted inner coil must not buckle or fail when unwinding and winding in. The frictional contact is sufficient between the spirally wound inner coil and the outer coil so that areas of unacceptably high compression or tension are not created between the two coils while they are on the coil. The spirally wound inner coil can, under certain circumstances, even improve the structural strength of the coil-in-coil tube as a whole.

Fig. 9 illustrates an embodiment for coil-in-coil pipe where an inner coil is spirally wound inside an outer coil and a wire cable or fiber optic cable or braided cable or the like is contained within the wire provided by the inner coil. Fig. 10, on the other hand, illustrates a concentric coil-in-coil arrangement. In fig. 10, the centering unit CN holds the inner coil tube ICT which defines a first wire IC, centered inside the outer coil tube OCT. A second annular fluid conduit AC is defined in the annular space between the inner coil ICT and the outer coil OCT. Fig. 10 illustrates the cable w placed in the ring-shaped wire AC.

Fig. 11 schematically illustrates a bottom hole string package BHA consisting of several units. Coil-in-coil pipe CNCT having the cable W located inside the inner coil is shown attached to a unit Ul. The unit Ul may be an adapter, preferably a universal head for coil-in-coil pipe for connection to a downhole string package, so that both wires IC and AC are in fluid contact with the package BHA.

In the downhole string package BHA, each unit, U2 - U8, may denote a different tool or measuring instrument or packing or spacer. The downhole string package BHA is shown with the tools and/or instruments connected and being prepared for connection at its upper end with the coil-in-coil tubing head. Units U1 through U8 would be provided for interconnection so that fluid communication is continued through most, if not all, units with both first lead IC and second lead AC, as well as with cable W.

Fig. 12 illustrates that a pack can easily be placed in an early unit such as unit U2. Fig. 13 illustrates packing PK set in a relevant section in a borehole. One of the conduits bounded by the coil-in-coil tube could be used to supply fluid to set the packing, as well as to aid in emptying or release. The gasket PK is illustrated as having an inner sleeve through which the tube CNCT moves back and forth in a sealing manner. Analogous gaskets have been discussed and can be adapted to work with coiled tubing.

Fig. 14 illustrates alternative methods for building coil-in-coil pipes. For illustrative purposes, Fig. 14 illustrates the outer coil tube OCT extended substantially horizontally. The inner coil tube ICT is illustrated as being simultaneously pulled through the outer coil OCT by the cable CB. The inner coil ICT is also pushed mn into the outer coil OCT by a coil tube injector, illustrated schematically as CTI. In addition, ICT is illustrated as being connected at the far end with a plug PL. A pump P is illustrated as pumping fluid in the annulus between the outer coil OCT and the inner coil ICT, whereby the plug PL is pressed to pump the inner coil ICT through the outer coil OCT. Fig. 15 illustrates the use of data management for the monitoring and operation of complex operations such as alternating testing, processing and testing. A computer CPU is illustrated in electrical connection through line L with a cable WL extending through the coil-in-coil tube CNCT and into and through connectors located in the work drum or coil R/S. The computer CPU can collect real-time data through cable connection as well as control downhole tools such as setting and deflating packings, opening and closing valves, operating drills and orientation tools and flushing tools and pumping tools and motors.

EXAMPLE: SYSTEM FOR TESTING, TREATMENT, TESTING

Flow testing of oil and gas reservoirs is a critical operation used by operators in both open hole and cased hole applications. The information obtained from drill string testing (DST) at open hole, permeability, flow rates, casing damage and water production is used to determine the well's deliverability and justifies lining the well. Alternatively, many wells are production tested after they have been lined to gather additional well information that establishes reservoir boundaries and the presence of casing damage. In wells with large production zones (horizontal), production tests are often used to selectively determine the source of well production, hydrocarbon or water, to allow relief measures.

Although well testing is common in almost all reservoirs, the testing of sour gas wells and horizontal wells is still a significant challenge for both operators and service companies. Testing of acid wells has been very limited due to concerns that H2S makes drill pipe brittle and for the overall safety of the well site when acid gas is produced to the surface. Without DST data, operators will in most cases have to rely on assessment of limited geological log and open hole log to determine the well's deliverability which justifies the execution of the well. In horizontal wells, the challenge is to selectively test the horizontal section of the well and use this information to implement stimulation measures to improve production.

The new technology according to the current example uses an inflatable field packing tool placed in vertical or horizontal wells using a "coil-in-coil" construction of the coiled tubing string. An electrical conductor is located within the inner string, which allows for "real-time formation, assessment and tool operation. The inner coil string is used for all well flow and stimulation operations with the coil-in-coil cavity used for circulation operations and inflation of Importantly, the outer string also provides pressure monitoring, flow shutoff and well control in the unlikely event of an inner string failure.

This is in contrast to the testing of wells that has been part of the oil and gas industry since the first oil wells were drilled many years ago. Historically, after drilling a well to the target formation, many operators will conduct a flow test of the formation of interest using DST tools that are fed back into the well on the drill pipe. This drill pipe#, which is often empty, is brought into position over the zone of interest, and then the packing elements are expanded through pipe rotation or settling weight. A valve in the DST tool is opened, whereby formation fluids are allowed to flow into the emptied drill pipe, and if there is sufficient bottomhole pressure (BHP) and flow capacity, this will lead to well production to the surface. However, if the BHP is not sufficient, the well will continue to flow into the drill pipe until its hydrostatic pressure is equal to the reservoir pressure. The tools are then closed and extracted from the well, and the produced fluid is measured and analyzed. In the earliest years of DST use, only well flow data was available. This information, in combination with open hole logs, was valuable in order to confirm that the well potential was sufficient to justify holding the well and continuing a completion. Later advances in the understanding of well flow and reservoir deliverability led to the use of downhole pressure gauges and transient pressure analyzes to obtain information on formation permeability, wellbore damage and DST tool performance. Some of today's DST tools use data transfer technology to enable the acquisition of pressure loss and pressure build-up data during the test, which enables optimization of well flow and build-up duration. The value of the DST data must not be underestimated as a means of obtaining critical well information before assuming the cost of drilling and completing wells whose deliverability may be marginal.

Unfortunately, the development of sour gas and oil formations and the subsequent growth in horizontal drilling have presented significant challenges to the use of traditional DST tools. Sour wells are today still tested to a very limited extent due to safety and overall costs. During the testing of a sour well, the drill pipe is exposed to H2S in the produced oil or gas. Since most drill pipe is made of high tensile steel with a Rockwell hardness in excess of 22 Rc, the drill pipe is prone to embrittlement by H2S. As a result, most operators will not use the drill pipe for acid flow tests, but will leave it alone or discard the drill pipe and run a new string of acid pipe to perform the DST operation. After the test operations are completed, the pipe is laid back down and the drill pipe is used either to exit the well or treat the hole for casing operations.

DST data is important in all well evaluations, but particularly in the case of carbonaceous reservoirs, since open hole logging does not adequately address the issue of well deliverability with the same degree of reliability as is available from similar logs for sandstem reservoirs. Consequently, the operator is very interested in any additional information on well deliverability, reservoir pressure and borehole skin damage that will give the operator certainty in the decision to £6 or abandon the well. The decision to put casing and then complete the well will cost the operator in the range of CS 400k - 600k based on a typical 11,500 ft (3,500 m) sour gas well. However, the decision to abandon the well and bypass a significant discovery has a more serious impact on future profitability.

Another limitation of current DST tool technology is the ability to quickly assess multiple zones in a well and to recover test fluids from each test. In a traditional subhydrostatic DST with drill pipe, formation fluid is extracted into the drill pipe. In order to analyze this fluid for water, drilling filtrate and hydrocarbons, the DST tools are required to be brought to the surface. Although real-time data transfer is available via Wet-Connect and electromagnetic systems, both currently have their challenges. With the Wet-Connect system, each time it is necessary to reset the tool over a new production zone, the cable/wet joint up. Once the tools are above the new vent zone, the cable must be fed into the hole (RIH) of the wet joint and re-establish electrical connection. With the EM system, depth and geology are the main limitations.

Horizontal wells present a similar challenge for existing well testing tools even if the requirement is not to obtain

data to support a "put casing - don't put casing" decision, but to obtain well flow and transient pressure data to allow for the maximization of well production and recoverable reserves. Horizontal drilling has evolved as

a cost-effective technology to promote well production in existing low-pressure wells or tight reservoirs with low delivery capacity. Although most horizontal wells lead to increased well production, both hydrocarbon and water have

the operator unfortunately has limited resources to confirm where the respective well flows actually come from along the extended open hole section,

Many of the most successful horizontal wells are in heterogeneous reservoirs where the formation geology varies significantly, leading to missed production when using vertical well development. In most horizontal wells, the open hole section is extended in length with a number of changes in well porosity and permeability along the open hole length. Consequently, the well's ability to deliver varies considerably in both hydrocarbon and water production. In vertical wells, today's tools for logging open holes and lined holes can be used to confirm a well's delivery capability based on previous well experience. Unfortunately, the use of these same tools in horizontal wells is not as effective. Similarly, the use of production logging tools, although successful in vertical wells, is very limited in horizontal wells due to open hole condition, open hole length, stratified flow, subhydrostatic reservoirs and cost.

The most viable technology today for use in testing horizontal wells in Canada has been the use of inflatable area packs that are placed in the well on spliced tubing and placed over a selected area of the open hole. Pressure recorders are placed in the BHA, and the well is suctioned in with a plunger to obtain inflow data specific to the test zone, after which the well is shut in at the surface to build up pressure. The area packing unit is then pulled out of the hole (POOH), and the recorded pressure and retrieved fluids

is analyzed to predict borehole skin and estimate production data. If it is clear, a decision is made to

undertake a selective stimulation which would require reintroduction into the well and repeated setting of the packings over the production zone of interest. After stimulation/assessment, the process must be repeated several times to cover a 3,000 ft (900 m) open hole section. It is obvious that this method is both time-consuming, expensive and will provide data of limited quality.

Both in sour well development and horizontal well development, there is a need for a downhole tool design and placement system that will allow for the area seal testing of several zones, retrieval of reservoir fluid sample without the need for POOH and real-time data for transient pressure. The design must also allow for stimulation or flow modification in the specific evaluation zone based on the real-time evaluation of the flow composition, velocity and transient pressure data without the tool string having to be removed.

While the preceding review reviewed the limitations of current technology in terms of filling the need for evaluation/stimulation/evaluation at DST for vertical sweet and sour oil and gas wells and similar service operations for horizontal wells, the following review will review the operational features of the optimal test system and the advantages of these features for actual operations.

For flow capability in sour production, the system must be able to be continuously exposed to conditions with significant acid gas without regard to situations with axial load. Minimal number of connections as well as means of monitoring the condition of the string would be a plus.

For real-time data acquisition and tool control, collecting data via a real-time system is essential to optimize both the duration of flow and pressure build-up as well as to optimize stimulation or treatment for flow profile modification. The pressure build-up data must be of sufficient length and sensitivity for transient-pressure analysis for borehole permeability and casing. The optimal system would consist of wireline telemetry (higher data transmission than other current systems) which allowed for continuous readings on the surface and operation of tools down the hole without movement of the pipe.

For sample retrieval to the surface, there is a need in both vertical and horizontal wells to retrieve bottom hole samples to the surface during testing if the well's BHP is insufficient to support sustained flow. In some cases, it would be advantageous if the fluid could be recovered during the test while the well was shut in at the formation surface for build-up.

For opportunities for stimulation/flow profile modification

in both the horizontal and vertical cases, it is possible to perform a formation treatment while the tools are still placed over the previously tested area. This helps to minimize repeated setting of packing and enables assessment during and after stimulation is complete. Real-time readings during the treatment would make it possible to optimize the treatment. How can production be maximized better than by measuring a borehole lining, stimulating to

remove the borehole liner, relieve treatment fluids and then re-assess to confirm results, all within the same test area and immediate time frame.

For gas production opportunities, the minimum gas production opportunity is preferably, but not necessarily, in the order of 56,600 - 84,900 mVdag to ensure sufficient reservoir development to confirm reasonable gas flow rates at a corresponding formation flow pressure. In addition, the tapping is necessary to allow for sufficient pressure build-up data for the transient-pressure analysis.

Mmimum fluid flow capability is preferably, but not necessarily, in the order of 200 - 300 barrels/day to again ensure sufficient reservoir drawdown to be able to predict deliverability and for pressure build-up analysis.

When emptying open hole sections with large thickened tools, the ability to get stuck has been greatly increased. The history of working with inflatable packings in open-hole DST situations shows that overpull mg up to 1,379 kg/cm<2> (8,900 daN) is occasionally required. The ability to slightly underbalance the inner string so that the inflatable pack "sucks" onto the inner string stem would be beneficial since all inflatable packs retain some setting after their initial inflation. The ability to circulate from below to move or dissolve debris that may have accumulated on top of the packs while they were set would also be beneficial.

Of the 6,000 DSTs conducted in Canada during 1995, over 98% were shallower than 11,500 feet (3,500 m).

Spanning the correct zone is essential. Real-time gamma and CCL included in the toolkit would help in most matters.

Since an open hole section is never accurate, an inflatable element is preferred to allow setting in smaller washout locations. Since one of the tool's requirements is to test several zones quickly, a straddle configuration is necessary.

The surface equipment is very similar to a traditional wireline logging operation with coiled tubing. Essentially, a standard coiled tubing assembly plus a monitoring truck collects the downhole DST data and controls the electrically actuated downhole valves. The part of the CT surface layout that has been modified is the work drums which have two rotary joints, one to the inner coil and the other to the coil-in-coil space, plus one standard cable assembly. This will enable continuous logging (CCL/gamma), ability to operate downhole valves plus collect pressure and temperature data during RIH/POOH and continuous circulation through each of the annulus. It will also allow the system to be of a closed-loop design, so that acidic/hydrocarbon-based fluids do not need to be cleaned away when the tools are to RIH/POOH.

The coiled tube string construction consists of a 2.375" (60.3 mm) outer coil with a 1.25" (31.8 mm) coil located inside. A wire cable with three conductors is housed inside the coil of 31.8 mm. All acidic/corrosive fluids will flow only through the 31.8 mm coil, while fluid for inflating the packings or gas that lifts the well will be pumped down the coil-in-coil annulus. Pulling and pushing via the injector head will only be applied to the outer coil. With this larger dimension coil, good horizontal reach can be achieved, even with a heavy BHA.

Due to the BHA's weight (907 kg), OD (127 mm) and length (+/-9.3 - 27.8 m), the coiled tubing DST coupling will be positioned in a similar manner to a standard DST . After being suspended below the rotary table in a set of V-belts, the CT injector will be swung over the BHA<1> and connected. This coupling has a built-in safety release, should the BHA become stuck downhole, plus a feed-through for 3 conductors. Due to the difficulty of rotating each end of the unit during tightening, it is locked in a manner similar to a snap fastener.

The heart of the BHA consists of two microprocessors which are connected via the cable to a computer on the surface. This enables continuous two-way communication with the electronic section built into the BHA. The system is capable of full data acquisition as well as complete control of all downhole functions.

Two inflatable gaskets provide the opportunity to isolate certain segments of the borehole during flow tests or treatment for stirring/flow profile modification. Inflating the gaskets is carried out by applying pressure through the coil-in-coil annulus. Since this annulus can be circulated to wash away fluids (where the returns are carried up the 31.8 mm pipe), it eliminates the potential clogging of inflation ports with well waste. It also eliminates the potential for the internal packing cavity to fill with acidic, corrosive, hydrocarbon-containing or aromatic fluids. The pressure inside the packings as well as the external borehole pressure are continuously monitored throughout the operation.

Unlike traditional systems with inflatable gaskets, where the pressure can only be equalized after a test, these gaskets can be RIH and POOH in an underbalanced state (less pressure on the inside than on the outside). This keeps the packings completely collapsed and reduces the possibility of bumping into borehole bridges when entering the well, or of the packings getting stuck after emptying due to accumulated waste on top of them. It also reduces the chance of a pressure drop or pressure shock in the well during POOH/RIH.

The minimum wellbore pressure at which various sustained production rates can be achieved in an 11,500 ft (3,500 m) vertical length through the inner 31.8 mm string is shown below. In the case of oil, production is aided by nitrogen gas lift where the nitrogen gas is fed down the annulus between the inner and outer CT strings.

Four (see Fig. 5A) of the downhole fluid restriction valves are computer controlled, electronically activated valves that have been field tested in existing drill string test (DST) systems. One is hydraulic. These valves control the flow of fluids between the different components of the system. They are discussed in more detail below: The first valve controls the flow of fluids from the annulus between the area seals and the inner coiled tubing string. This "flow valve" (VI) normally controls the flow of formation fluids from the well into the inner coil string and is a valve with two positions (open/closed). It can also be used to inject fluids from the inner string and mn into the borehole between the two packings for stimulation, flow profile modification or circulation purposes.

The "inflation valve" (V2) is a three-position valve, which in the "inflation/deflation" position allows fluid from the coil-in-coil annulus to be pumped into the packings for inflation purposes or to relieve this pressure at the end of a test. The "closed" position seals off any pressure (negative/overpressure) contained within the gaskets, thereby enabling pressure control of the coil-in-coil annulus. In its third position, "circulation", fluid can be circulated between the inner coil and the coil-in-coil annulus in either direction.

The "equalizing valve" (V3) is a valve with two positions (open/closed), which allows fluid exchange between the three separate borehole areas formed when the two inflate

packings are inflated - the area above and below the packing area and the area between the two packings. This helps to equalize the pressure above and between the seals before they are emptied. It also precludes the possibility of rupture of the zone of interest while the seals are still being inflated (whereby fluid is trapped between the two seals before full expansion is reached).

The "injection valve" (V4) is a valve with two positions (open/closed), which enables fluids to be pumped down the coil-in-coil annulus and injected into the borehole's annular area.

The "relief valve" (V5) is a hydraulic valve with a safety pin, which protects the gaskets from being overinflated, but has a secondary purpose. Should the electronic signal to the surface ever fail, too much pressure on this valve will open it, allowing the seals to empty.

The following pressures are monitored continuously during all operations at a 5 second sampling rate.

On the surface:

1. Inner coil (pressure measurements in closed chamber or in open flow).

2. Press in the outer coil.

Down in the hole:

1. External pressure between the seals (formation

pressure), two manometers.

2. Hydrostatic pressure in the borehole.

3. Inflation pressure inside the gaskets.

4. Inner coil above the flow valve (exhaust pressure).

5. Coil-in-coil annulus pressure.

The temperatures down the hole are also recorded continuously. A gamma ray and CCL correlation log is included in the tool kit to provide well depth control for critical test and stimulation operations during RIH/POOH and packing setting.

One of the primary reasons for the development of this system was safety, particularly in the application area of testing sour oil and gas wells. There are a number of safety features that are in the actual design of this system and are aimed at safety. These include: Barriers to hold pressure and fluid are available brought through the coil-in-coil system. Continuous monitoring of the outer coil pressure makes it possible to immediately detect any leakage in the inner coil and to stop testing.

Construction materials for the equipment: All materials used in the fluid handling components of this system follow the specifications in NACE MR-175. The coiled pipe is manufactured from an A-606 type 4, modified metallurgy that has been used in a number of application areas within acidic environments over the years. The cable jacket is made of Incology 825, and the downhole tools of either 4140 carbon steel heat treated to 18-22 Rc or of 17-4PH stainless steel heat treated to Hl150 - 1150 specifications.

The small volume of the inner coiled tubing string minimizes the amount of acidic fluids and hydrocarbons contained in the test string, reducing the hazard in well control situations.

Retrieving the test tools with the packings under underbalanced pressure conditions reduces the risk of suction of borehole fluids during extraction from the well.

If the BHA has become stuck, and traditional methods cannot release it, the BHA can be released by applying pressure upwards in the inner string. If electrical power has also been lost, and the valves are in the open position, voltage can be applied to the BHA to close a check valve downhole, allowing pressure setting.

If electrical power is lost and the gaskets are still inflated, pressure can be applied down the coil-in-coil annulus to open a bleed port. If the downhole valve is open, a downhole opening still allows the generation of enough differential pressure to be generated during pumping to open the gate.

The procedures to be followed will vary depending on the well design and the objectives of the assessment and/or stimulation program for the well. The following procedures include the most common anticipated situations:

Introduction of BHA into the well for well evaluation:

1. The inner string is filled with air or nitrogen depending on the well depth. 2. The outer string is partially or completely filled with liquid, depending on the BHP. 3. Pressure in each of the two strings can be regulated during introduction into the hole. 4. All downhole valves are normally closed during introduction into the hole. 5. The circulation system in the tools will allow borehole fluids to circulate through the tool to avoid the fluids being forced into the formation by the piston effect if the clearance between the borehole and the tool is limited. 6. The outer string will be slightly underbalanced compared to the borehole pressure below RIH to keep the packings fully collapsed and reduce the potential for premature setting when filter cake or tight hole conditions are encountered.

Package inflation

1. The gaskets are inflated by opening the inflation valve and applying external string pressure until the gasket inflation pressure is 300 - 500 psi (2,000 - 3,500 kPa) above

BHP.

2. The inflation valve is then closed, thereby trapping pressure in the gaskets. Additional pressure can be applied at any time by pressurizing the outer string and opening the inflation valve.

Assessment

The most significant aspect of this system delivered through coiled tubing is the flexibility it brings to the formation assessment process. It is expected that all the operations to be carried out with this technology will begin with an evaluation phase which will normally consist of at least one flow period and one build-up period. - The flow valve connecting the wellbore to the inner string is opened electronically to allow produced fluids to flow into the inner string. The inner string volume is approximately 11.5 barrels (1.8 m<3>). - The initial (pre-flow) period is usually conducted under closed chamber conditions, which provides real-time measurements of two-phase flow rate. Subsequent flow periods can also be carried out under conditions with a closed chamber when the flow rate is small, or where safety and reliability are of great importance. - Pressure and flow rate data can be monitored continuously in the cab at the well site or monitored remotely at the well operator's office.

Interpretation

The value of this technology for well operators lies not only in the quality of the data that is collected, but even more importantly in the ability to interpret and utilize that data instantly to maximize operational efficiency.

The essential ingredients for an optimized well test interpretation with the system described above are:

- two-phase flow rate information on a real-time basis.

- Sample description and analysis before the test ends.

- Reservoir parameters from the well operator. Porosity, net production, fluid saturations, etc.

- Staff on site trained in well test interpretation.

- Adequate real-time pressure build-up data for radial (direction perpendicular to the borehole) (or other flow scheme) analysis. - Flexibility to lift gas to maintain the necessary reservoir inflow. - Well test interpretation software package, which provides semi-log and log-log analysis as well as the ability to model and predict productivity removed by damage. - A communication system between the field and the well operator's head office to ensure the possibility of quick decisions.

Stimulation/profile modification

Treatment fluids will normally be pumped down through the inner string with returns carried up either through the outer coil/casing annulus or coil-in-coil annulus. These lines' discharge/intake ports are preferably spaced 1.35 m apart with the inner coil port just below the upper gasket. This gives the opportunity to spread the treatment fluid directly over the majority of the interspace before clamping operations begin.

Circulation of produced fluid

During final shut-in, or after the packings have been emptied, the produced fluids within the inner string can be circulated to the surface for sampling and emplacement of hydrocarbons and acidic fluids. Traditional drill string testing systems require the use of wellbore fluid to circulate produced fluids from the test string, which gives rise to well control issues and limits circulation operations to after completion of the test, in addition these systems require the entire test string to be brought to the surface for resetting of the circulation valve after it has been opened, as the valve cannot be closed.

The coil-in-coil string plus electronic valve control system provides many advantages in terms of circulation. The circulation valve can be opened and closed an unlimited number of times, allowing circulation of produced fluids after each test during multiple test sequences without withdrawal from the hole. Fluids from the coil-in-coil annulus are used to circulate produced fluids from the inner string, allowing well control capabilities to be maintained with the borehole fluid. The outer coil fluid will be a clean fluid and will provide a better boundary layer to the produced fluids, while circulating borehole fluids can lead to ambiguity since they sometimes resemble the produced fluids. Circulation can rather be carried out during the last confinement period of the test than using operating time after the end of the test. It also allows samples to be collected and analyzed several hours earlier.

Emptying of gaskets

The gaskets are deflated by opening the inflation valve and allowing pressure to drain to the outer string. By using a fluid in the outer string with a lower density than the borehole fluids, the packings can be taken back to a slightly underbalanced state after emptying. This reduces the potential for the tools to become stuck in the well.

A new cable-controlled, DST system with concentric coiled tubing has been developed for testing, stimulation and profile modification of sour and/or horizontal wells.

The new system has a number of user benefits as outlined above, namely: safety, sour equipment, circulation control, inflatable elements, multiple sets, test-treatment-test and gas lift capabilities, real-time surface reading, on-site interpretation and direct data transfer - guidance to head offices.

The system's real-time capabilities will lead to optimization of rig time. The system's flexibility and intrinsic safety will also allow for faster completion of these critical operations.

The preceding mention and description of the invention is illustrative and explanatory of it. Various changes in size, shape and materials as well as in the details of the illustrated structure can be made without going beyond the scope of the invention.

Claims (45)

1. Apparatus for use in well operations, such as treatment or forming or testing or measuring and the like, and in combinations of the above operations, where the apparatus comprises a coil-in-coil tubing string (21) including a radially inner length of coil tubing (102) located within a radially outer coiled tube length (100), which coiled tube lengths (100, 102) delimit a first inner fluid line (82) and a second annular fluid line (80) located between said coiled tube lengths (100, 102), where the apparatus also comprises a bottom hole string package ( BHA) which is adapted to be attached to a portion of said coiled tubing string (21), so that the bottom hole string package (BHA) is in fluid communication with both of said fluid joint members (80, 82), and that at least one packing piece (108, 110 ) is arranged to be connected to said bottom hole string package (BHA) or the said pipe lengths (100, 102) in the coiled tubing string (21), and that said bottom hole string package (BHA) includes at least two tools (1 12) selected from the group consisting of a drilling tool, a production/testing tool, a vacuum tool (suction pump), a treatment injection tool, a pumping tool, a perforating tool, a tool orientation device, an electric motor, a hydraulic motor, a flushing tool, and a measuring device (measuring instrument), or includes means for production through both lines from formations above or below the packing piece (108, 110) when this is set in the borehole. 2. Apparatus according to claim 1, characterized in that the coil-in-coil pipe string (21) essentially consists of a steel coil pipe length (102) with a smaller diameter which is fed into a steel coil pipe length (100) with a larger diameter. 3. Apparatus according to claim 1, characterized in that the inner coil tube length (102)'s smallest outer diameter is 2.54 cm (1 inch), while the outer coil tube length (100)'s smallest outer diameter is 5.08 cm (2 inches). 4. Apparatus according to claim 1, characterized in that said pump comprises a pump selected from the group consisting of a jet pump, a chamber lift pump and an electric pump. 5. Apparatus according to claim 1, characterized in that the apparatus includes a cable (66) which extends through one of said two fluid lines (80, 82) in order thereby to create an electrical connection between the surface and the downhole string package (BHA). 6. Apparatus according to claim 5, characterized in that said cable (66) comprises at least one conductor with a braided or twisted wire. 7. Apparatus according to claim 1, characterized in that the apparatus includes means for transmitting data from said bottom hole string package (BHA) through said borehole (120). 8. Apparatus according to claim 1, characterized in that said bottom hole string package (BHA) includes a variable distance regulating unit. 9. Apparatus according to claim 7, characterized in that said bottom hole string package (BHA) includes at least one measuring device/instrument which is in connection with said transmission means. 10. Apparatus according to claim 9, characterized in that said measuring device/instrument includes at least one instrument from the group consisting of a temperature measuring instrument, a pressure measurement device, a resistance measuring device, a gamma ray logging tool, a sonar logging tool, a neutron logging tool, a logging device cloth unit, a range meter (volume flow meter), a densitometer, a chemical analysis unit, a casing collar placement device, and a downhole fluid measurement and analysis unit. 11. Apparatus according to claim 1, characterized in that said at least one packing piece (108, 110) includes a portal packing. 12. Apparatus according to claim 1, characterized in that said at least one gasket piece (108, 110) includes a gasket which is designed to be slidably attached to the coil-in-coil pipe string (21). 13. Apparatus according to claim 5, characterized in that the coil-in-coil tube string (21) is coaxial, and that said cable (66) is placed in the annular fluid line (80). 14. Apparatus according to claim 7, characterized in that said transmission means comprises a coaxial or fiber optic cable (66). 15. Apparatus according to claim 1, characterized in that the bottom hole string package (BHA) is designed to be attached to an end portion of said coiled tubing string (21). 16. Apparatus according to claim 1, characterized in that the apparatus includes a drum/coil (14), and that said coil-in-coil pipe string (21) is at least partially wound up on said drum/coil (14). 17. Apparatus according to claim 1, characterized in that said packing piece (108, 110) is designed to be connected to said bottom hole string pack (BHA). 18. Apparatus according to claim 1, characterized in that the bottom hole string pack (BHA) includes means for producing through both fluid lines (80, 82) from the for-mason above and below the packing piece (108, 110) when this is set in the borehole (120). 19. Apparatus according to claim 7, characterized in that said means for transferring data includes means for transferring data in real time. 20. Procedure for use in well operations, such as treatment or shaping or testing or measurement and the like, and in combinations of the above operations, where the procedure includes the following action steps (a) introducing into a borehole (120) a coil-in-coil tubing string (21), where the tubing string (21) includes a radially inner coiled tubing length (102) positioned inside a radially outer coiled tubing length (100), which coiled tubing- lengths (100, 102) define a first internal fluid line (82) as well as a second annular fluid line (80) situated between said coiled pipe lengths (100, 102), and where the coiled pipe string (21) is provided with a bottom hole string package (BHA) which is designed to to be attached to a portion of said coiled tubing string (21), such that the downhole string package (BHA) is in fluid communication with both of said fluid conduits (80, 82), the downhole string package (BHA) including at least two tools selected from a group consisting of a drilling tool, a production, testing and/or processing tool, a vacuum tool, a pumping tool, a perforating tool, a perforating tool, a tool orientation device, an electric motor, a hydraulic motor, a flushing tool and a measuring device, and/ or that said downhole string package (BHA) includes means for production through both fluid lines (80, 82) from the formation above and below the packing piece (108, 110) when this is set in the borehole (120), and said downhole string package (BHA) includes at least one packing piece (108, 110) adapted to connect to one of said fittings and said pipe; (b) setting at least one packing piece (108, 110) in the borehole (120); and (c) transferring a fluid through both fluid lines, either up or down through the coil-in-coil tube string (21). 21. Method according to claim 20, characterized in that the method also includes the following steps: (b) setting of at least one packing piece (108, 110) in the borehole (120) and in its drilling fluid, the packing piece (108, 110) being aligned to be connected to said bottom hole string package (BHA) or said pipe lengths (100, 102) in the coiled tubing string (21); (c) production of borehole fluid from an area below the packing piece (108, 110), the borehole fluid being produced through at least one of the two fluid lines (80, 82) of the coiled pipe string (21); (d) injecting well treatment fluid through at least the first inner fluid line (82) of the coiled tubing string (21), the well treatment fluid being injected to an area below the packing piece (108, 110); and (e) then producing the borehole fluid through at least one of the coiled pipe string (21)'s two fluid lines (80, 82), the borehole fluid being produced from an area below the at least one packing piece (108, 110). 22. Method according to claim 21, characterized in that the borehole fluid flows from the first internal fluid line (82) and/or the annular fluid line (80) without contaminating the drilling fluid above the packing piece (108, 110). 23. Method according to claim 20, characterized in that the method comprises the following steps: (a) connecting a coil-in-coil pipe string (21) to a bottom hole string package (BHA), where the coil pipe string (21) includes a radially inner coil pipe length (102 ) positioned inside a radially outer coiled pipe length (100), which coiled pipe lengths (100, 102) delimit a first internal fluid line {82) and a second annular fluid line (80) situated between said coiled pipe lengths (100, 102), and where the connection is made as follows that the two fluid lines (80, 82) are in fluid communication with said bottom hole string package (BHA); (b) placing said bottom hole string package (BHA) down a wellbore (120), which bottom hole string package (BHA) includes a well treatment tool; (c) sealing between a part of the combination of the coil-in-coil tubing string (21) and the bottom hole string package (BHA) and a part of the wellbore (120)'s wall, the sealing being carried out by means of at least one packing piece (108, 110) ; (d) transferring well treatment fluid into a formation (104) that delimits the borehole (120), the well treatment fluid being transferred through at least one of said two fluid conduits (80, 82) and through said well treatment tool; (e) producing borehole fluid up through the annular fluid conduit (80); and (f) flushing the borehole fluid from the annular fluid conduit (80) by circulating fluid through the first fluid conduit (82) and the second fluid conduit (80). 24. Method according to claim 23, characterized in that the sealing in point (c) is carried out in the borehole (120)'s drilling fluid. 25. Method according to claim 24, characterized in that the flushing is carried out without contaminating the drilling fluid above the seal. 26. Method according to claim 24, characterized in that the method comprises inflating the at least one packing piece (108, 110). 27. Method according to claim 20, characterized in that the method comprises the following action steps: (a) introduction into a drill hole (120) of a coil-in-coil pipe string (21) carrying a drilling tool (112) and at least one packing piece (108/110), where the coiled pipe string (21) includes at least a first internal fluid line (82) and a second annular fluid line (80), the first fluid line (82) being delimited by a radially internal coiled pipe length (102) , while the second fluid conduit (80) is defined between the inner coiled tube length (102) and a radially outer coiled tube length (100); (b) setting the at least one packing piece (108, 110) in the borehole (120); and (c) overbalancing of drilling fluid in the borehole (120) above the packing piece (108, 110) and underbalancing of fluid in the borehole (120) below the packing piece (108, 110). 28. Method according to claim 27, characterized in that the sealing in (b) includes sealing between the coil-in-coil pipe string (21) and a part of the borehole (120)'s wall, so that the coil-in-coil pipe string (21) is occupied sealing and sliding through said gasket (108, 110). 29. Method according to claim 23, characterized in that the method includes production of borehole fluids up through the second annular fluid line (80), after which a treatment fluid is transferred down through one of said fluid lines (80, 82), after which borehole fluids are produced up through the annular fluid line (80). 30. Method according to claim 23, characterized in that the method includes circulating a treatment fluid down through one of said fluid lines (80, 82), after which borehole fluids are produced up through one of said fluid lines (80, 82), after which a treatment fluid is circulated down through one of said fluid lines (80, 82). 31. Method according to claim 23, characterized in that said sealing includes isolation of a part of said borehole (120) between a pair of packing pieces (108, 110). 32. Method according to claim 31, characterized in that the method includes circulation of fluids down through one fluid line (80, 82) and up through the other fluid line (80, 82) for flushing out fluids in the isolated zone. 33. Method according to claim 20, characterized in that the method comprises the following steps: (a) connecting a coil-in-coil pipe string (21) to a bottom hole string package (BHA), where the coil pipe string (21) includes a radially internal coil pipe length (102 ) positioned inside a radially outer coiled tube length (100), which coiled tube lengths (100, 102) delimit a first inner fluid line (82) and a second annular fluid line (80) situated between said coiled tube lengths (100, 102), and where the connection is made as follows that the two fluid lines (80, 82) are in fluid communication with said bottom hole string pack (BHA); (b) placing said bottom hole string package (BHA) down a wellbore (120); (c) sealing between a portion of the combination coil-in-coil tubing string (21) and downhole string package (BHA) and a portion of the wellbore (120) wall; and (d) pumping fluid down through both fluid lines (80, 82) to at least a portion of said bottom hole string package (BHA), the fluid either constituting a well treatment fluid or a hydraulic working fluid for a tool associated with the bottom hole string package (BHA) . 34. Method according to claim 33, characterized in that the fluid that is pumped down each fluid line (82, 80) comprises a different chemical, and that the chemicals are chosen to produce a chemical reaction when they are mixed in the borehole (120). 35. Method according to claim 20, characterized in that the method comprises pumping gas down through one fluid line (80, 82) and liquid down through the other fluid line (80, 82). 36. Method according to claim 20, characterized in that the method comprises the following action steps: (a) connecting a coil-in-coil pipe string (21) to a bottom hole string package (BHA), where the coil pipe string (21) includes a radially inner coil pipe length (102) positioned inside a radially outer coiled pipe length (100), which coiled pipe lengths (100, 102) delimit a first internal fluid line (82) and a second annular fluid line (80) located between said coiled pipe lengths (100, 102), and where the connection is made so that the two fluid lines (80, 82) are in fluid communication with said bottom hole string package (BHA); (b) placing said bottom hole string package (BHA) down a wellbore (120); (c) sealing between a portion of the combination coil-in-coil tubing string (21) and downhole string package (BHA) and a portion of the wellbore (120) wall; (d) circulating fluid down through one fluid conduit (80, 82) and up through the other fluid conduit (80, 82); and (e) driving a rotating tool down the hole (120) with a portion of said circulation fluid. 37. Method according to claim 20, characterized in that the method comprises the transfer of a fluid between the surface and the borehole (120) through one of said fluid lines (80, 82); and maintaining a heat-insulating fluid in the second of said fluid conduits (80, 82). 38. Method according to claim 23, characterized in that the method includes the use of fluid which is transferred through one fluid line (80, 82) for hydraulic operation of a tool which is attached to the bottom hole string package (BHA). 39. Method according to claim 20, characterized in that the method includes the following action steps: (a) connecting a coil-in-coil pipe string (21) to at least one bottom hole string package (BHA), where the coil pipe string (21) includes a radially inner coil pipe length (102) positioned inside a radially outer coil pipe length (100), which coil pipe lengths (100, 102) delimit a first inner fluid line (82) as well as a second annular fluid line (80) located between said coil pipe lengths (100, 102), and where the connection is made so that each of the two fluid lines (80, 82) is in fluid communication with a bottom hole string package (BHA); (b) placing at least one bottom hole string package (BHA) down a wellbore (120), wherein said bottom hole string package (BHA) comprises at least one packing piece (108, 110) and means for producing fluids from two different formation production zones, of which one formation production zone located on either side of the at least one packing piece (108, 110); (c) setting at least one packing piece (108, 110) in the borehole (120); and (d) production of fluid from one production zone up through the first fluid line (82), and production of fluid from the second production zone up through the second fluid line (80). 40. Method according to claim 23, 33, 36, 37 or 39, characterized in that said placement includes introduction of said coil-in-coil pipe string (21) from a drum/coil (14). 41. Method according to claim 21, characterized in that the method for assembling a coil-in-coil pipe string (21) comprises stretching a first length of coil pipe (100) essentially horizontally; and introducing a second coiled pipe length (102) through said first coiled pipe length (100) by means of a coiled pipe injector (156). 42. Method according to claim 21, characterized in that the method for assembling a coil-in-coil pipe string (21) comprises stretching a first length of coil pipe (100) essentially horizontally; and pulling a second length of coiled pipe (102) through said first length of coiled pipe (100) by means of a cable (66) which is fed in through said first length of coiled pipe (100). 43. Method according to claim 41, characterized in that the method includes pulling said second coiled pipe length (102) through said first coiled pipe length (100) by means of cable (66) which is led in through said first coiled pipe length (100). 44. Method according to claim 41, 42 or 43, characterized in that the method includes pumping the second coiled pipe length (102) through the final coiled pipe length. 45. Method according to claim 41, 42 or 43, characterized in that the method includes lubrication between the second and the first coiled tube length (102, 100).