Wells – Conduit wall or specific conduit end structure – Downhole coupling or connector
Reexamination Certificate
1999-08-27
2001-03-13
Mai, Lanna (Department: 3619)
Wells
Conduit wall or specific conduit end structure
Downhole coupling or connector
C166S117600, C166S050000, C175S045000, C175S171000
Reexamination Certificate
active
06199633
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates generally to wellbore construction and more particularly to the construction of multiple wellbores which are interconnected downhole to form a manifold of pipelines in the reservoirs of interest. Provision is made for flow controls, sensors, data transmission, power generation, and other operations positioned in the lateral wellbores during the drilling, completion and production phases of such wellbores.
2. Background of the Related Art
To obtain hydrocarbons such as oil and gas, wellbores or boreholes are drilled from one or more surface locations into hydrocarbon-bearing subterranean geological strata or formations (also referred to herein as reservoirs). A large proportion of the current drilling activity involves drilling deviated and/or substantially horizontal wellbores extending through such reservoirs. To develop an oil and gas field, especially offshore, multiple wellbores are drilled from an offshore rig or platform stationed at a fixed location. A template is placed on the sea bed, defining the location and size of each of the multiple wellbores to be drilled. The various wellbores are then drilled from the template along their respective pre-determined wellpaths (or drilling course) to their respective reservoir targets. Frequently, ten to thirty offshore wells are drilled from an offshore rig stationed at a single location. In some regions such as the North Sea, as many as sixty separate wellbores have been drilled from an offshore platform stationed at a single location. The initial drilling direction of several thousand feet of each such wellbore is generally vertical and typically lies in a non-producing (non-hydrocarbon bearing) formation.
Each wellbore is then completed to produce hydrocarbons from its associated subsurface formations. Completion of a wellbore typically includes placing casings through the entire length of the wellbore, perforating production zones, and installing safety devices, flow control devices, zone isolation devices, and other devices within the wellbore. Additionally each wellbore has associated wellhead equipment, generally referred to as a “tree” and includes closure valves, connections to flowlines, connections for risers and blowout preventors, and other devices.
As an example, ten wellbores may be drilled from a single offshore platform, each wellbore having a nine-inch internal diameter. Assuming that there is no production zone for the initial five thousand feet for any of the wellbores, there would be a total of fifty thousand feet (five thousand for each of ten wellbores) of non-producing wellbore that must be drilled and completed, serving little useful purpose. It may, therefore, be desirable to drill as few upper portions as necessary from a single location or site, especially as the cost of the drilling and completing offshore wellbores can range from $100 to $300 per foot of wellbore drilled and completed.
Multilateral well schemes have been proposed since the 1920's. Various methods of constructing these well geometry's have been disclosed showing methods of creating the wellbores, methods of mechanically connecting casings in the various wellbores drilled, methods of sealing the casing junctions, and various methods of providing re-entry access to the lateral wellbores for remedial treatments.
Multilateral wellbore junction construction is currently thought of as fitting into one of six levels of complexity. Level 1 is generally thought of as open hole sidetracks where lateral wellbores are drilled from an open hole (uncased) section of the main well. No casing is present in the main well or lateral well at the junction of the two wellbores. This method is generally the least expensive but does not ensure wellbore stability, does not provide a method of easy lateral re-entry, and it does not seal the junction in a manner to allow future flow control of the lateral versus the main wellbore.
Level 2 multilateral junctions are those where the lateral exits from a cased main well using section miling or whipstock methods to create the exit. The lateral wellbore may be left as open hole or a liner may be run and “dropped off” outside the main well casing exit such that the lateral liner and main casing are not connected and an openhole junction results. This method is currently a little more costly than Level 1; it provides some more assurance of re-entry access to laterals, and it can provide some flow control of the various wellbores. It does not however protect or reinforce the junction area against potential collapse of the open hole wellbore wall.
Level 3 junctions provide laterals exiting from a cased main well and a lateral liner is run in the lateral wellbore and mechanically connected to the main casing but no seal of the junction is achieved. This method supports the borehole created and provides access to laterals but the lack of a seal at the junction can lead to sand production or fluid inflow or outflow into the junction rock strata. In many applications this inflow or outflow of fluids at junction depth is not desirable as the laterals may penetrate strata of different pressures and the unsealed junction could result in an underground blow out.
Level 4 junctions also provide a lateral wellbore exiting from a cased main well and a lateral liner is run into the lateral wellbore with the top end of the lateral casing extending back to the main casing with the junction of the lateral liner and main casing sealed with cement or some other hardening liquid material that can be pumped in place around the junction. This method achieves isolation of the junction from adjoining strata providing a sufficient length annular seal can be placed around the lateral liner and provided the main casing has an annular seal between the casing and the main wellbore wall. Various methods of reentry access to the laterals is provided using deflectors or other devices. The pressure seal integrity achieved in this type of wellbore junction is generally dependent on rock properties of the junction strata and cannot exceed the junction strata fracture pressure by more than a few hundred pounds per square inch. In addition the guaranteed placement and strength of liquid cementatious hardening materials in a downhole environment is extremely difficult with washouts causing slow fluid velocities, debris causing contamination of sealing materials, fluid mixing causing dilution, gelled drilling muds resisting displacement, etc. The junction may be isolated from adjoining zones but seal reliability specifically at the junction is difficult.
Level 5 systems generally provide lateral wellbores exiting from a cased main well. Liners are run in the lateral wellbore and may be “dropped off” outside the window in the main casing or a Level 4 type cemented intersection may be created. The Level 5 systems however use production tubulars and mechanical packer devices to mechanically connect and seal the main casing and lateral liners to each other. Level 5 systems can achieve a junction seal exceeding the junction strata capability by five to ten thousand psi. These systems do however restrict the diameter of access to the lateral and main casings below the junctions due to the relatively small tubular diameters compared to casing sizes. Well designs must also generally consider the possibility of a leak in the junction tubulars. This limits the application of Level 5 systems to generally those applications where the junction pressures are abnormal for the junction rock only due to surface applied pressures such as may be encountered in injection wells or during well stimulations. Flow rates achievable through such junctions are also restricted to the rates possible through the smaller diameter tubulars.
Level 6 junctions create a mechanically sealed junction between the main casing and lateral liner without using the restricting bores of production tubulars to achieve the seal. The methods devised to date generally are of two categories. One category uses
Mai Lanna
Marnock Marvin J.
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