1. Field of the Invention

This invention relates generally to wellbore construction and more particularly to methods for forming multi-branched or multi-lateral wellbores

from one or more access wellbore At least one access wellbore is formed substantially in non-producing subterranean formations This invention also relates to methods of utilizing such wellbores, including utilizing the branch wellbores for storing various devices and materials for performing certain

operations in the branch wellbores This invention further relates to apparatus and method for transporting equipment and materials from a source location to a desired wellbore or between different wellbores

2. Background of the Art

To obtain hydrocarbons such as oil and gas, wellbores (also referred

to as boreholes) are drilled from one or more surface locations into

hydrocarbon-bearing subterranean geological strata or formations (also

referred to in the industry as the reservoirs) A large proportion of the current

drilling activity involves drilling highly deviated and/or substantially horizontal

wellbores extending through the reservoir Typically, to drill a horizontal

wellbore into a desired formation, the wellbore is drilled from a surface location vertically into the earth for a certain depth At a predetermined

depth, the wellbore is dog-legged into a desired direction so as to reach the

desired formation, which is usually the target hydrocarbon-bearing or producing formation. The wellbore is drilled horizontally into the producing formation to a desired length. Additional dog-legged wellbores from the same

vertical wellbore are also drilled in some cases Some horizontal boreholes extend several thousand meters into the reservoirs. In most cases, however, a single horizontal wellbore, generally referred herein as the primary wellbore, main wellbore or access wellbore, is drilled to recover hydrocarbons from different locations within the reservoir More recently, branch wellbores from the main wellbore that extend into selected areas of the producing formation or reservoir have been drilled to increase production of hydrocarbons from the reservoir and/or to maximize the total hydrocarbon recovery from the reservoir. Such a branch wellbore herein is referred to as a

lateral wellbore and a plurality of such branch wellbores extending from a wellbore are referred to as multi-lateral or multi-branched wellbores.

The primary wellbore and the multi-lateral wellbores are generally drilled along predetermined wellbore paths, which are usually determined or

plotted based on existing data, such as seismic data and drilling data available from previously drilled wells in the same or similar formation.

Resolution of such data is relatively low. To drill such wellbores, operators typically utilize a drill string which contains a drilling device and a number of measurement-while-drilling ("MWD") devices. The drilling device is used to

disintegrate the subsurface formations and the MWD devices are used for

determining the properties of the formations and for determining the

downhole drilling conditions Operators utilize the information to adjust the

drilling direction

In many cases it is desirable to form a primary wellbore in a non-

producing formation and then drill branch or lateral wellbores from the

primary wellbore into the target formation In such cases, it is highly

desirable to place the primary wellbore along an optimum wellbore path

which is at a known distance from the boundary of the target formations

Prior art typically utilizes seismic data and prior wellbore data to decide upon

the path for the primary wellbore The resolution of such data is relatively

poor Wireline tools can be run to obtain the necessary bed boundary information Wireline systems require stopping the drilling operations for

several hours and are thus not very desirable None of the prior art systems

provide in-situ determination of the location of the boundary of the target

producing formations relative to the wellbore being drilled It is, thus,

desirable to determine relatively accurately the location of the boundary of

the target formation relative to the primary wellbore while drilling the primary

wellbore Such information can then be utilized to adjust the drilling direction

to adjust the drilling direction to form the wellbore along an optimum wellbore

path

As noted above, current drilling methods and systems do not provide

m-situ means for determining the position of the target formation bed

boundary relative to a primary wellbore that is drilled in a non-producing

formation along the target formation Current directional drilling systems usually employ a drill string having a drill bit at its bottom that is rotated by a motor (commonly referred to as the "mud motor") A plurality of sensors and MWD devices are placed in close proximity to the drill bit to measure certain drilling, borehole and formation evaluation parameters Typically, sensors for measuring downhole temperature and pressure, azimuth and inclination measuring devices and a formation resistivity measuring device are employed

to determine the drill string and borehole-related parameters However, none

of these systems allow drilling an access wellbore at a known distance from the wellbore that is determined and adjusted while the access wellbore is being drilled

United States Patent Application Serial No 60/010,652, filed on January 26, 1996, which is assigned to the assignee of the present application and which is incorporated herein by reference, provides a system

for drilling boreholes wherein the downhole subassembly includes an acoustic MWD system in which a first set of acoustic sensors is utilized to determine the acoustic velocities of the borehole formations during drilling

and a second set of acoustic sensors for determining bed boundary

information based on the formation acoustic velocities measured downhole

Isolators between the transmitters and their associated receivers serve to

reduce the body wave and tube wave effects The present invention

preferably utilizes the system disclosed in the United States Patent

Application Serial No. 60/010,652 to determine the location of the bed

boundaries around the primary wellbore, including the bed boundaries of the

target reservoir relative to the primary wellbore while drilling the access

wellbore. The drilling direction or path of the primary wellbore is adjusted

based on the bed boundary information to place the primary wellbore at

optimum distance from the target formation. Since the location of the primary

wellbore is relatively accurately known in relation to adjacent formations, it

enables drilling branch wellbores along optimum paths into the target

formation and the non-producing formations.

In the prior art primary wellbores, a number of devices are placed to

facilitate production of hydrocarbons and to perform workover services. Such

devices occupy space in the primary wellbore, which may be utilized for

improving the overall efficiency of the wellbore system. Such primary

wellbores are expensive to construct, are relatively inefficient in transporting

hydrocarbons and are obstructive if major workover is required after the

completion of such wellbores. It is desirable to have branch wellbores for storing various types of equipment and materials downhole, including

retrievable devices which may be utilized for performing downhole

operations. It is also desirable to leave the primary wellbore substantially

free of any equipment and materials which may be placed outside the main

wellbore and to utilize the main wellbore primarily for transporting fluids

during the production of hydrocarbons. This may be accomplished by

storing certain devices in the storage wellbore and by installing the fluid flow

control devices entirely in the individual branch wellbores.

It is a common practice to form a seal around an area at the

intersection of the primary wellbore and the branch wellbores. The seal is

usually formed between the intersecting wellbores and the formation. Since

the prior art branch wellbores are formed from the primary wellbores placed

in the producing formations, the seals are formed entirely within such

producing formations Seals formed in the producing formations tend to be

less durable because such formations typically are relatively porous and also

because of the presence of depleting hydrocarbons It is therefore desirable

to form such seals entirely within the non-producing formations

United States Patent Applications Serial No. 08/41 1 ,377, filed March

27, 1996 and Serial No. 08/469,968, filed June 6, 1995, both assigned to the

assignee of this application, which are incorporated herein by reference in

their entirety, disclose forming branch wellbores from a primary wellbore,

wherein some of the branch wellbores are drilled outside producing

formations or the reservoirs for stoπng chemicals for treating the

hydrocarbons downhole and for re-injecting water into secondary formations.

Such wellbore construction solves some of the problems with the above-

noted prior art wellbore However, these methods do not provide wellbores

for storing retrievable devices therein which may be utilized downhole at a

later time, such as for performing completion operations, perforating, or

performing workover tasks or transferring certain chemicals from such

storage wellbores to another location downhole during the drilling of branch

wellbores or at a later time, such as after the hydrocarbon production has started. Additionally, such wellbores do not provide for forming seals which lie outside the producing wellbores or primary wellbores which are utilized

primarily for transporting fluids during the production phase.

The present invention addresses the above-noted problems associated with formation and use of multi-lateral wellbores and provides

methods for forming multi-lateral wellbores from a primary wellbore which is formed substantially in a non-producing formation. The distance between the primary wellbore and the target formations is determined while drilling the primary wellbore, preferably by acoustic means. The drilling path of the

primary wellbore is altered or adjusted based on the in-situ distance measurements to place the primary wellbore along an optimum path. The lateral wellbores are drilled from the primary wellbore in the non-producing

formations and producing formations. Seals are formed at the intersection of the lateral wellbores and primary wellbore entirely in the non-producing

formation. Lateral wellbores are utilized for a variety of purposes, including

for storing equipment and for processing and treating fluids downhole. Fluid

flow control devices are placed outside the primary wellbore. The primary

wellbore is utilized primarily for flowing the hydrocarbons.

SUMMARY OF THE INVENTION

The present invention provides methods and systems for forming multi- lateral wellbores In one method, a primary or access wellbore is formed

substantially in a non-producing formation At least one production branch

wellbore is formed from the access wellbore into a hydrocarbon-bearing

formation for recovering hydrocarbons from such a formation At least one branch wellbore is formed for storing retrievable apparatus which may be utilized later for performing an operation downhole Additional lateral

wellbores may be formed from the access wellbore or the branch wellbores

for storing therein materials and equipment which may be utilized downhole

later One such branch wellbore may be formed for storing certain chemicals

that are selectively discharged into the hydrocarbons during production

Another branch wellbore may be formed to contain a fluid separation system

for separating downhole hydrocarbons into different phases or for separating

hydrocarbons from other fluids such as water

The present invention provides for forming seals between the access

wellbore and the production wellbores entirely in the non-hydrocarbon

bearing formations Additionally, flow control apparatus for controlling fluid

flow from the producing formations through the production branch wellbores

may be located entirely outside the access wellbore to facilitate the fluid flow

through such production branch wellbores

The production branch wellbores and other branch wellbores are

completed Hydrocarbons then flow from the producing formations into their

associate production wellbores Such multi-lateral wellbore construction

allows utilizing the access wellbore for primarily transporting fluids during

production of hydrocarbons and provides more access space for remedial

and or service operations

In another method of the present invention, the distance between the

access wellbore and the producing formations is determined during the

drilling of the access wellbore In one method acoustic sensors deployed in a drilling assembly are utilized for determining the distance between the access

wellbore and the desired formations In an alternative method seismic

measurement are utilized for determining such distance while drilling the

access wellbore The distance determined may be utilized for adjusting the

drilling path of the access wellbore either from the surface or by deploying

devices that would automatically adjust the drilling direction based on the computed distance

The methods of the invention provide for retrieving the stored devices

in the branch wellbores for performing a function downhole The stored

devices may include devices for drilling wellbores, for perforating wellbores,

for performing wellbore completion operations, for performing workover

operations and for taking wellbore measurements.

The present invention further provides a system for transporting

devices or materials to and from any desired branch wellbore

Examples of the more important features of the invention have been

summarized rather broadly in order that the detailed description thereof that

follows may be better understood, and in order that the contributions to the

art may be appreciated There are, of course, additional features of the

invention that will be described hereinafter and which will form the subject of

the claims appended hereto

BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present invention, references should

be made to the following detailed description of the preferred embodiment,

taken in conjunction with the accompanying drawings, in which like elements

have been given like numerals, wherein

FIG. 1 shows a schematic illustration of forming an access wellbore in

a non-producing formation while determining the location of the target

formations relative to the access wellbore

FIG. 2 is a schematic diagram showing the formation of lateral

wellbores formed from the primary access wellbore at selected places into the

non-producing and producing formations.

FIG. 3 is a schematic diagram showing the formation of seals at the

intersection of the primary wellbore and the branch wellbores that are placed

entirely in the non-producing formation

FIG.4 shows the placement of retrievable devices in a branch wellbore,

chemicals in a separate branch wellbore and processing apparatus in yet

another separate branch wellbore, thereby enabling utilizing the access

wellbore primarily or entirely for flowing fluids therethrough

FIG. 5 is a schematic diagram showing the placement of flow control

apparatus outside the primary wellbore

FIG. 6 is a schematic diagram showing the formation of

interconnecting access wellbores in a non-producing and producing

formation, wherein lateral production wellbores are formed from the access

wellbore in the producing formation

FIG. 7 is a schematic diagram showing a primary access wellbore

which avoids certain producing formations and which is drilled into a certain

producing formation

FIG. 8A is a schematic diagram of the primary access wellbore with a

multi-concentric tubing for flowing fluids therethrough

FIG. 8B is a schematic diagram of the primary access wellbore with

multiple tubings placed therein for flowing fluids therethrough

FIG. 9A is a schematic diagram of a transport system for use in placing

devices and materials in the branch wellbores

FIG. 9B is a side of the transport system of FIG. 9B

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

In general, the present invention provides methods and systems for

forming multi-lateral wellbores from one or more primary access wellbores

FIGS. 1 -5 illustrate the formation of lateral wellbores from an access wellbore

that is formed primarily in a non-producing formation FIGS. 6 and 7 illustrate

examples of forming branch wellbores from access wellbores formed in both

a non-producing and a producing formation Branch wellbores made from a

single access wellbore are first described followed by the formation of branch

wellbores from multiple access wellbores Apparatus and method for

transporting devices and materials into the wellbores is described thereafter

FIG. 1 shows a schematic diagram of a preferred drilling system 10 for

drilling wellbores offshore The drilling system 10 includes a drilling platform

12, a drill string 30 having a drilling apparatus and various measurement-

while-dπllmg ("MWD") devices at its bottom end The combination of the drilling apparatus and the MWD devices are sometimes referred to herein as the "downhole assembly" or the "bottomhole assembly" or "BHA" and is

denoted numeral 45 The bottomhole assembly 45 is utilized for drilling an

access wellbore 20 through the subterranean formations and for making

measurements relating to the subsurface formations and drilling parameters

during the drilling of the access wellbore 20 The drilling platform 12 includes

a derrick 14 erected on a floor 16 which supports a rotary table rotated by a

prime mover (not shown) at a desired rotational speed The drill string 30

includes a tubing 32 that extends downward from the rotary table into a

primary or main access wellbore 20 A bottomhole assembly 45 is attached

to the bottom end of the tubing 32 for drilling the wellbore 20 The drill string

30 is coupled to a drawworks via a kelly joint, swivel and line through a

system of pulleys to hold the drill pipe 32 Such elements are well known in

the art for forming wellbores and are, thus, not shown or described in any detail

A control unit 40 is preferably placed on the platform 12 The control

unit 40 receives signals from the MWD devices and other sensors placed

downhole and on the surface, processes such signals, and aids in controlling

the drilling operations according to programmed instructions. The surface

control unit 40 includes devices for displaying desired drilling parameters and

other information, which information is utilized by an operator to control the

drilling operations. The surface control unit 40 contains a computer, memory

for storing data, data recorder and other peripherals. The surface control unit

40 also includes models and processes data according to programmed

instructions and responds to user commands entered through a suitable

means, such as a keyboard. A number of alarms 44 are coupled to the

control unit 40, which selectively activates such alarms when certain unsafe

or undesirable operating conditions occur. Such control systems are known in the art and, thus, are not described in detail.

The bottomhole assembly 45 preferably includes a drill motor or mud

motor 55 coupled to a drill bit 50 via a drive shaft (not shown) disposed in a

bearing assembly 57 for rotating the drill bit 50 when a fluid 31 is passed

through the mud motor 55 under pressure. A lower stabilizer 58a is provided

near the drill bit 50, which is preferably placed over the bearing assembly 57,

to acts as a centralizer for the lowermost portion of the bottomhole assembly

45. Additional stabilizers, such as a stabilizer 58b, are suitably placed along

the bottomhole assembly for providing lateral support to the bottomhole

assembly 45 at desired locations.

Still referring to FIG. 1, the BHA preferably contains a formation

resistivity device 64 for determining the formation resistivity near and in front

of the drill bit 50, a gamma ray device 65 for measuring the formation gamma

ray intensity and an inclination measuring device (inclinometer) 74 for

determining the inclination and azimuth of the bottomhole assembly 45 The

resistivity device 64 contains one or more pairs of transmitting antennae 66a

and 66b spaced from one or more pairs of receiving antennae 68a and 68b

Magnetic dipoles are employed which operate in the medium frequency and

lower high frequency spectrum In operation, the transmitted electromagnetic

waves are perturbed as they propagate through the formation surrounding

the resistivity device 64 The receiving antennae 68a and 68b detect the

perturbed waves Formation resistivity is derived from the phase and

amplitude of the detected signals Signals from these devices and other

sensors are processed by a downhole circuit and transmitted to the surface

control unit 40 preferably a suitable two-way telemetry system 72

The inclinometer 74 and the gamma ray device 76 are preferably

placed along the resistivity measuring device 64 for respectively determining

the inclination of the portion of the drill string near the drill bit 50 and the

formation gamma ray intensity Any suitable inclinometer and gamma ray

device may be utilized for the purposes of this invention In addition, an

azimuth device (not shown), such as a magnetometer or a gyroscopic device,

may be utilized to determine the drill string azimuth Such devices are known

in the art and, thus, are not described in detail herein In the above-

described configuration, the mud motor 55 transfers power to the drill bit 50

via one or more hollow shafts that run through the resistivity measuring

device 64 The hollow shaft enables the drilling fluid to pass from the mud

motor 55 to the drill bit 50 In an alternative embodiment of the drill string 20,

the mud motor 55 may be coupled below resistivity measuring device 64 or at

any other suitable place

The downhole assembly 45 preferably includes a section 78 which

contains an acoustic system 70 for determining the distance between the

access wellbore 20 and adjacent formations, such as target or producing

(hydrocarbon-bearing) formations 82 and 84 Producing formations are also

referred herein as reservoirs The acoustic system contains transmitters and

one or more sets of receivers (not shown) The system is adapted to transmit

acoustic signals at a desired number of frequencies or by sweeping

frequencies in a given range The transmitted acoustic signals reflect from

the formations 82 and 84 and the reflected signals are detected by the

receivers The detected signals are processed to determine the distance "d"

between the access wellbore and the target formations The frequencies of

the transmitted signals are chosen to obtain a desired depth of investigation

and the resolution Such a method enables in-situ determinations of the

distance between the bed boundaries of the target formations 82 and 84 from

the bottomhole assembly 45

United States Patent Application Serial No 60/010,652, which is

assigned to the assignee of this invention and which is incorporated herein

by reference in its entirety, discloses an acoustic system for determining the

bed boundaries from a bottomhole assembly The present invention

preferably utilizes such an acoustic system for determining the distance d

The present invention, however, may utilize any other known system for

determining the bed boundary information Such systems may include

seismic methods in which receivers are deployed in drill string or the BHA

and a source is placed at the earth's surface or vice versa

Still referring to FIG. 1 , the section 78 also includes devices for

determining the formation density, formation porosity and other desired

formation evaluation parameters The section 78 is preferably placed above

the mud motor 55 Such devices are known in the art and the present

invention may utilize any such devices These devices also transmit data to

the downhole telemetry system 72, which in turn transmits the received data

uphole to the surface control unit 40 The downhole telemetry system 72 also

receives signals and data from the uphole control unit 40 and transmits such

received signals and data to the appropriate downhole devices The present

invention preferably utilizes a mud pulse telemetry technique to communicate

data from downhole sensors and devices to the control unit 40 during drilling

operations Any other communication system also may be utilized

Still referring to FIG. 1 , in one method of forming wellbores, the drilling

system 10 is utilized to drill the access wellbore 20 through a non-producing

or non-hydrocarbon-beaπng formation 80 along a predetermined wellbore

path a certain distance from the hydrocarbon-bearing formations, such as

formations 82 and 84 Such a predetermined wellbore path is typically

defined based on prior information, such as seismic data and data relating to

prior wellbore formed in the same or nearby geological formations During

the drilling of the access wellbore 20, the acoustic device 70 continually

determines the distance d between the wellbore 20 and the target formations

82 and 84 As noted earlier, prior art systems do not attempt to drill the

access wellbores primarily in a non-producing formation and also do not

determine the relative location of the target formations while drilling the

access wellbore In the present invention, the bed boundary information

obtained by the bottomhole assembly 45 is preferably utilized to adjust the

drilling direction of the access wellbore 20 from the surface or by deploying

self-adjusting apparatus downhole that may be controlled from the surface or

which is self-actuating based on the distance d determined by the bottomhole

assembly 45 and the desired distance Such method enable drilling the

access wellbore along an optimal wellbore path and enables adjusting the

drilling path bases on relatively accurate in-situ measurements taken during

the drilling operations

Typically, the access wellbore, such as the wellbore 20, is

substantially larger than the lateral wellbores that are to drilled from the

access wellbore Therefore, access wellbores require use of large rigs,

which are expensive to operate Therefore, it is desirable to first drill the

access wellbore to a sufficient distance from the surface and then drill lateral

wellbores by utilizing smaller rigs, which are usually referred to as the

workover rigs

The access wellbore 20 is preferably formed entirely or substantially

entirely in non-producing formations for reasons which are more fully

explained later Once the access wellbore 20 has been formed to a desired

depth, a desired number of non-production lateral or branch wellbores are

formed from the access wellbore 20 As an example and not as a limitation,

FIG. 2 shows an example of forming non-production branch wellbores Non-

production branch wellbores 102, 104 and 106, each having a desired reach

or depth, are shown formed from the access wellbore 20 into the non-

producing formation 80 Wellbores 102, 104 and 106 respectively intersect

the wellbore 20 at locations 103, 105, and 107 The non-production branch

wellbores may also be formed from production branch wellbores 110 and

112. The non-production wellbores may be utilized for a variety of purposes

as explained in more detail later with reference to FIGS. 4 and 5

It is desirable to form the branch wellbores in a non-producing

formation because they usually are less porous than the producing

formations and are, thus, harder than the producing formations. The non-

producing formations, thus, enable forming stronger and more durable

wellbores less expensively Some of such wellbores, however, may be

formed in the producing formations In addition to the desired non-production

wellbores 102, 104, and 106, a desired number of production wellbores are

formed from the access wellbore 20 into the producing formations 82 and 84

As an example, and not as any limitation, FIG. 2 shows the formation of two

production wellbores 110a and 110b respectively from locations (points of

intersection) 111a and 111b at he access wellbore 20 into the producing

formation 82. Similarly, a production branch wellbore 112 is formed from the

access wellbore 20 into the producing formation 84 Knowing the distance of

the producing formations 82 and 84 from the access wellbore 20 enables

planning and drilling the branch wellbores 110a, 110b and 112 along

optimum wellbore paths

It is known in the art that it is desirable to drill the wellbores in the

producing formations, such as formations 82 and 84, with a drilling fluid that

is different from the fluid utilized for drilling the wellbores or portions thereof

in the non-producing formations This is due to the fact that commonly used

drilling fluids for drilling wellbores through the non-producing formations can

cause productivity impairment in the producing formations If this occurs, this

usually requires stimulating the formation to allow the producing formation to

reach its maximum potential.

The fluids used for drilling in the producing formations are referred to

in the art as the "drill-in" fluids. Current methods require having two complete

fluid systems The wellbore fluid is changed each time a wellbore is drilled

into a producing formation In the example of FIG. 2, the drilling fluid would

be changed when the branch wellbore 110a is drilled past the location 110a".

The drilling fluid will again be changed when the branch wellbore 110a has

been drilled and the drilling is continued to drill the access wellbore 20 past

the branch wellbore 110a Thus, for the purpose of this invention, it is

preferred that the wellbores, both the access wellbore and the branch

wellbores, first be formed in the non producing formations to the extent

practical by utilizing one type of drilling fluid and then changing the fluid to

drill the branch wellbores in the producing formations Thus, the present

invention requires changing the drilling fluid only once, i e , after the access

wellbore and other branch wellbores have been drilled into the non-producing

formations to the extent practical

After drilling the branch wellbores as described above, seals are

formed at respective branch wellbore junctions with the access wellbore 20.

FIG. 3 shows the formation of such seals. As shown, seals 154 and 156 are

respectively formed at the intersection of the access wellbore 20 and the non-

production branch wellbores 102 and 104 It may be desirable not to form

any seal between certain branch wellbores and the access wellbore 20 as

shown for the branch wellbore 106. Similarly, seals are formed between the

access wellbore 20 and the production branch wellbores 110a, 110b and

112. As noted earlier, since the rocks are usually harder in the non-

producing formations, such as the formation 80, it is preferred that the seals

for the production wellbores, such as wellbores 110a, 110b and 112, are

formed entirely in the non-producing formation 80. Such seals are easier to

form and are more durable. Various types of seals and methods of forming

seals are known in the oil and gas industry. For the purpose of this invention any such seals may be formed.

Still referring to FIG. 3, the production wellbores are completed at

desired zones. For example, wellbore 110a is completed at zone 162a for

producing hydrocarbons from the formation 82. Additionally, the wellbore

110b is completed at two locations 162b ^* and 162b" for producing additional

hydrocarbons from the formation 82. Similarly, wellbore 112 is shown

completed at a zone or location 164 for producing hydrocarbons from the

formation 84. It should be noted that any number of wellbores may be formed

in each of the producing formations and each such wellbore may be

completed at any number of zones for optimizing the production of

hydrocarbons. Furthermore, any suitable completion method may be utilized

for performing completion operations.

FIG. 4 shows the completion of non-production wellbores 102, 104 and

106 and some examples of how such wellbores may be utilized. Wellbore

102 is shown to contain a liner or casing 202 for protecting the wellbore from

collapsing. In certain hard formations and/or certain shallow wellbores, it

may not be necessary to use such methods for protecting the wellbore. In

FIG. 4, wellbore 102 is shown as a place for storing devices. The stored

devices are denoted generally by numeral 204. Once the desired number of

storage wellbores, such as wellbore 102, have been suitably completed,

devices 204 may be conveyed into and retrieved therefrom as desired. As

shown in FIG. 4, devices 204 may be conveyed into the storage wellbores

102 via a casing 240 placed in the access wellbore 20 and a suitable

closable opening 205 between the access wellbore 102 and the casing 240

by any suitable method, including by coiled tubings. The devices 204 may be

self-propelled and may be activated from a remote location, such as the

surface or a location in any of the wellbores via a suitable communication

apparatus. Thus, such a device would contain certain amount of local

intelligence. The devices 204 may be programmed to self-actuate upon the

occurrence of a condition to perform an operation downhole. Thus, the

devices 204 may be autonomous. The devices 204 may be retrieved from

the wellbore 102 for performing a suitable operation downhole. Examples of

the devices that may be stored in the storage wellbores include: (a)

bottomhole assemblies, which may include a drill bit, drilling motor and

measurement-while drilling devices (b) individual measurement-while-drilling

devices and/or other sensors for use in determining formation, drilling,

wellbore and production parameters, (c) devices for use in completing

wellbores, (d) perforating devices, (e) packers, (f) compressors; (g) pumps;

(h) perforating devices; (i) flow control devices; and (j) other devices that may

be utilized downhole during the formation of the wellbores described above

and/or for later use during the production of hydrocarbons from the target

formations.

Still referring to FIG. 4, the non-production branch wellbore 104 has a

junction 154 and is lined with a casing 206 This wellbore is shown to house

materials 208, which may be utilized for processing or treating fluids

downhole. The stored materials 208 may include chemicals and/or biological

masses (enzymes) The chemicals and/or biological masses may be utilized

for treating downhole fluids to alter the viscosity, to change the chemical

composition or chemical make-up of fluids downhole, i.e., in one of the

wellbores. In practice, to treat the downhole fluids with the stored materials,

such materials may be controllably released into the access wellbore 20

through a release path 210 and a suitable control device 207. Alternatively,

the fluids from the access wellbore 20 may be passed into the wellbore 104

via a suitable line 207' for treatment with the stored materials. The treated

fluids may then be returned to the access wellbore 20 via the fluid control

device 207. The fluids may be treated to alter the viscosity of the downhole

fluids so as to reduce drag, change the chemical structure and/or chemical

make-up of the downhole fluids, including the hydrocarbons

In FIG. 4, the branch wellbore 106 is shown to contain equipment 222

and materials for processing and/or treating fluids downhole Additionally,

materials, such as chemicals and biological masses, generally denoted by

numeral 223, may also be stored for use with the equipment 222 The fluids

219 may be passed from the access wellbore 20 into the wellbore 106 via

suitable conduit 225a The equipment 222 treats or processes the received

fluids 219 and discharges the treated fluids either back into the access

wellbore 20 or to another wellbore (not shown) The equipment 222 may

include equipment for separating downhole fluids into various constituents,

such as solids, water, oil and gas In one embodiment, water may be

separated from oil and gas The separated water may be discharged into a

dump wellbore (not shown) and the oil and gas may be returned to the

access wellbore 20 for transportation to the surface This allows for more

efficient transportation of hydrocarbons from the producing formations

In another embodiment, the wellbore 106 the equipment 222 may

include equipment and for processing hydrocarbons downhole Such

equipment may utilize chemicals or other materials 223 for processing the

hydrocarbons As an example, production fluid may first be treated to remove

any water and solids therefrom The hydrocarbons may then be processed or

treated to produce other materials, such as octane, pentane, toluene,

benzene, methanol, naphtha, fuel oil, gasoline, diesel, jet fuel, lube oil,

asphalt, etc Processing equipment, chemicals and/or biological masses 223

may be utilized to produce such materials. It should be noted that the

processing wellbores, such as the wellbore 106, may be located at any other

desired location, such as above each of the producing branch wellbores, such as wellbores 110a, 110b and 112. Additionally, multiple wellbores may

be utilized to accomplish the processing and treatment of the fluids downhole.

For example, one wellbore may be utilized to remove solids and water from the fluids and another wellbore for treating and/or processing the hydrocarbons. Thus, one of the purposes of such wellbores may be to

eliminate or reduce the processing of fluids and/or hydrocarbons on the

surface. Additionally, heating equipment and electrical equipment may be utilized in a branch wellbore to treat /or alter the state of a fluid downhole.

Still referring to FIG. 4, the branch wellbores, such as wellbore 106,

may be utilized to contain equipment such as compressors for compressing any gaseous vapors in the fluid downhole. Such compressors may be utilized to compress the gas and discharge the compressed gas into a producing

formation to aid the production of hydrocarbons from such a formation. Alternatively, the gas may be compressed into a liquid form and discharged

into the access wellbore 20 for transportation to the surface.

In the present invention, the non-production wellbores 102, 104 and

106 are preferably, but not necessarily, formed entirely or substantially in the

non-producing formations. The non-production wellbores are preferably utilized for performing desired operations downhole for improving the overall

efficiency of recovering and/or processing hydrocarbon recovery, improving

the life of the various wellbores and/or reducing costly operations at the

surface.

FIG. 5 shows examples of the placement of flow control devices

outside both the primary access wellbore 20 and the producing formations,

and the placement of processing equipment in the primary access wellbore.

In the example of FIG. 5, a separate fluid flow control device is placed in each

of the production wellbores 110a, 110b and 112. Accordingly, flow control

devices 300a and 300b are respectively placed in production wellbores 110a

and 110b while a flow control device 304 is placed in the wellbore 112. The

fluids recovered from the formations 82 and 84 pass to the access wellbore

via these control devices. The fluid control devices 300a, 300b and 304 may

be controlled from the surface. These flow control devices 300a, 300b and

304 are preferably remotely and independently controllable from the control

unit 40. These flow control devices are adjusted to optimize the production of

hydrocarbons from the various producing formations. This also allows

shutting down a specified production branch wellbores to perform workover or

service operations. The flow control devices 300a, 300b and 304 may be

made to communicate with each other so that they may automatically adjust

the fluid flow from their associated wellbore according to programmed

instructions. These devices may also be programmed to completely close if

certain predetermined adverse conditions occur. Additionally, these flow

control devices may be operated as a function of certain parameters of interest, such as the pressure in the branch wellbores.

Still referring to FIG. 5, the above-noted devices may be deployed in

the primary access wellbore 20. Devices placed in the primary wellbore are

generally denoted by numeral 307. Such devices may be used for treating

and/or processing fluids downhole as described above in reference to equipment 222 (FIG. 4). The equipment 307 may be utilized alone or in

conjunction with materials (chemicals, etc.) stored in one of the branch

wellbores, such as wellbore 106. The processing and treatment of the fluids

may be done in the manner described earlier.

The use of non-producing wellbores to store devices and materials to perform desired operations, and the use of flow control devices outside the access wellbore allows the access wellbore to be maintained substantially free from devices that are not utilized for flowing fluids through the access

wellbore. In other words, during the production of hydrocarbons, the access

wellbore remains free of devices and materials which might negatively affect

the flow of hydrocarbons to the surface.

The discussion thus far has related to the formation of multi-lateral

wellbores from a primary wellbore that is formed primarily in a non-producing formation. In some applications, it may be desirable to form more than one

access wellbore. FIG. 6 shows a manner of forming multi-lateral production

wellbores from an access wellbore formed in the producing formation 82. In

this configuration, the access wellbore 20 is formed as described above with

in reference to FIG. 1. Additionally, the remaining wellbores are formed as

described in reference to FIGS. 2-5 with the exception of wellbores 110a and

110b. Instead, a second access wellbore 402 is formed from the access

wellbore 20 into the formation 82. A desired number of lateral wellbores

404a-d are then formed from the access wellbore 400 into the producing

formation 82. Seals 406a-d are formed between the access wellbore 402

and branch wellbores 404a-d respectively. These seals are formed within the

producing formation 82 by any suitable method known in the art. The branch

wellbores are 404a-d are respectively completed at zones 408a-d Fluid flow

control devices are preferably placed in each of the producing branch

wellbores to independently adjust the fluid flow through each such production

wellbore. In each of the wellbore configurations herein the various fluid flow

control devices may communicate with each other to control the

corresponding fluid flows and/or may be controlled independently from a

remote location such as the surface.

FIG. 7 shows an alternative method of forming wellbores. In this

method, the primary wellbore 20 is formed away from some of the reservoirs,

such as reservoirs 82 and 84, and drilled into some of the reservoirs, such as

a reservoir 420. Hydrocarbons from the formations 82, 84 and 420 may be

produced in the manner described above or by any other known method.

Such a method is useful when it is desired to drill the primary access wellbore

into one or more reservoirs, such as reservoir 420, and avoid drilling it in to

one or more reservoirs, such as reservoirs 82 and 84. Such a method allows

placing the primary access wellbore along an optimal path and allows the

production of hydrocarbons from each such reservoir. It should be noted that

additional access wellbores (not shown), similar to the wellbore 112, may be

formed from the primary access wellbores into the reservoir 420.

FIGS. 8A and 8B show the use of multi-paths for flowing fluids through

the access wellbore 20. FIG. 8A shows two concentric conduits or tubings,

having an outer tubing 450a and an inner tubing 450b. More than two

concentric tubings may also be utilized. These concentric tubings may be

utilized instead of the single tubing 240 as shown in FIGS. 4 and 5. Fluid

flow control devices 452a and 452b are installed respectively in tubings 450a

and 450b to control the flow of the fluids through their associated tubings.

Such an arrangement allows for better control of the fluid flow compared to

the single tubing 240. New wellbores tend to produce larger amounts of

hydrocarbons, which amounts gradually reduce as the producing formations

are depleted. In such cases, for high production rates, the larger (outer)

tubing 450a alone or in conjunction with the inner tubing 450b may be utilized

for flowing fluids to the surface. This may be accomplished by opening the

devices 452a and 452b. As the fluid flow decreases due to change in

pressure or due to the increased amount of water production, one of the

tubings may be closed. Additionally, this arrangement may be utilized to flow

different materials to the surface. For example one of the tubings may be utilized to flow water and solids to the surface and the other tubing for flowing hydrocarbons.

FIG. 8B shows an alternative arrangement of utilizing multiple tubings

in a wellbore. FIG. 8B shows the use of two different sized tubings 470a and

470b placed side-by-side in the access wellbore 20. Fluid flow control valves

472a and 472b are respectively placed in the tubings 470a and 470b for

controlling the fluid flows through their respective tubings. The flow through

these tubings may be controlled by independently controlling the flow control

devices 472a and 272b. The flow control valves shown in FIGS. 8A and 8B

are preferably remotely controllable from the surface. The above described

arrangements provide for better control of the flow of fluid through the access

wellbore 20 over the life of the producing wellbores without requiring

secondary work to insert smaller tubings after the completion of the access

wellbore 20.

FIGS. 9A and 9B show an apparatus which may be utilized for placing

into and retrieving from any of the wellbores equipment and materials. FIG.

9A shows an access wellbore 510 having an inside diameter "dr and branch

wellbores 512a-c with respective diameters d ₂ ^. Each of the diameters d _2Jt is

smaller than the diameter d^ The device or tool 520 to be moved into a

desired branch wellbore is detachably attached or coupled to a carrier 522

This can be accomplished by making the size of the carrier 522 greater than

each of the openings 514a-c The dimensions of the carrier are such that it

may be passed over the branch wellbores 512a-c To convey the device 520

into a desired wellbore, the carrier 522 is coupled to a conveying device 524,

such as a tubing The device 520 is coupled to the carrier 522 or the

conveying device 524 The conveying device is then moved in the wellbore

510 to position the carrier 522 before the desired wellbore For example, if

the device 522 is to be conveyed into the wellbore 512b, the carrier is

positioned as shown by the dotted lines 522' before the wellbore 512b The

carrier 520 is then detached from the conveying device 524 while leaving the

device 520 attached to the conveying device 524 The device 520 is then

conveyed by the convening device into the wellbore 512b Since the device

52 is smaller than the opening of the wellbore 512b, the device 520 may be

conveyed in to the wellbore by utilizing any of the techniques known in the

art After the device 520 has been properly positioned in the wellbore 512b,

the conveying device is detached from the device 520 and used to retrieve

the carrier 522 from the access wellbore 510 To retrieve a device from any

of the wellbores, the process described above is reversed Fluids, such as

chemicals and other materials, may also be conveyed into a desired wellbore

in the manner described above

In an alternative embodiment, as shown in FIG. 9B, the carrier 540

includes a number of adjustable members 532, each member preferably

being independently adjustable radially. Such members may be mechanically

adjustable or remotely adjustable so that they expand and collapse about the

body 530. To convey a device, the adjustable members are moved to

suitable positions to convey the device 520. If remotely adjustable members

are utilized, the carrier may not need to be detached prior to conveying the device into a destination wellbore. If the destination wellbore is sufficiently

large to accommodate both the carrier and the device to be conveyed, then

the combination may be conveyed into the destination wellbore and the

carrier detached after positioning the device in the destination wellbore.

Such a carrier may be utilized to retrieve a device from the wellbore with the

members collapsed to the body, which are then expanded to pass over other

branch wellbores and repositioned to convey the device into a second wellbore.

While the foregoing disclosure is directed to the preferred

embodiments of the invention, various modifications will be apparent to those

skilled in the art. It is intended that all variations within the scope and spirit of

the appended claims be embraced by the foregoing disclosure.