Wells – Processes – Cementing – plugging or consolidating
Reexamination Certificate
1997-12-19
2001-05-15
Neuder, William (Department: 3672)
Wells
Processes
Cementing, plugging or consolidating
C166S294000
Reexamination Certificate
active
06230804
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates generally to methods and compositions for cementing, and more specifically to methods and compositions for cementing in high stress environments. In particular, this invention relates to methods and compositions for well cementing utilizing mixtures of hydraulic cement and aluminum silicate and/or fibrous materials such as wollastonite, in high stress environments such as encountered in multi-lateral well completions.
2. Description of Related Art
Cementing is a common technique employed during many phases of wellbore operations. For example, cement may be employed to cement or secure various casing strings and/or liners in a well. In other cases, cementing may be used in remedial operations to repair casing and/or to achieve formation isolation. In still other cases, cementing may be employed during well abandonment. Cement operations performed in wellbores under high stress conditions may present particular problems, among other things, difficulty in obtaining good wellbore isolation and/or maintaining mechanical integrity of the wellbore. These problems may be exacerbated in those cases where wellbore and/or formation conditions promote fluid intrusion into the wellbore, including intrusion of water, gas, or other fluids.
In a wellbore, cement may be used to serve several purposes. Among these purposes are to selectively isolate particular areas of a wellbore from other areas of the wellbore. For example, cement is commonly placed in the annulus created between the outside surface of a pipe string and the inside formation surface or wall of a wellbore in order to form a sheath to seal off fluid and/or solid production from formations penetrated by the wellbore. This isolation allows a wellbore to be selectively completed to allow production from, or injection into, one or more productive formations penetrated by the wellbore. In other cases cement may be used for purposes including, but not limited to, sealing off perforations, repairing casing leak/s (including leaks from damaged areas of the casing), plugging back or sealing off the lower section of a wellbore, sealing the interior of a wellbore during abandonment operations, etc.
The economic success of a drilling operation often hinges upon the ability to establish zonal isolation within a cemented wellbore. Once established, maintaining this zonal isolation is typically impacted by the particular stress environment found while the well is being completed and produced. During the life of a well, the cement sheath may be exposed to stresses imposed by well operations including perforating, hydraulic fracturing, high temperature-pressure differentials, etc. Further, if the well is completed using a complex completion such as a multi-lateral system, the cement sheath may be subject to shattering and subsequent loss of bond due to pipe impact.
Conventional well cement compositions are typically brittle when cured. These conventional cement compositions often fail due to stresses, such as compressional and/or shear stresses, that are exerted on the set cement. Wellbore cements may be subjected to shear and compressional stresses that result from a variety of causes. For example, stress conditions may be induced by relatively high temperatures and/or relatively high fluid pressures encountered inside cemented wellbore pipe strings during operations such as perforating, stimulation, injection, testing, production, etc. Stress conditions may also be induced or aggravated by fluctuations or cycling in temperature or fluid pressures during similar operations. Variations in temperature and internal pressure of the wellbore pipe string may result in radial and longitudinal pipe expansion and/or contraction which tends to place stress on, among other things, the annular cement sheath existing between the outside surface of a pipe string and the inside formation surface or wall of a wellbore. Such stresses may also be induced in cement present in other areas of the wellbore in the pipe.
In other cases, cements placed in wellbores may be subjected to mechanical stress induced by vibrations and impacts resulting from operations, for example, in which wireline and pipe conveyed assembly are moved within the wellbore. Hydraulic, thermal and mechanical stresses may also be induced from forces and changes in forces existing outside the cement sheath surrounding a pipe string. For example, overburden and formation pressures, formation temperatures, formation shifting, etc. may cause stress on cement within a wellbore.
Conventional wellbore cements typically react to excessive stress by failing. As used herein, “cement failure” means cracking, shattering, debonding from attached surfaces (such as exterior surfaces of a pipe string and/or the wellbore face), or otherwise losing its original properties of strength and/or cohesion. Stress-induced cement failure typically results in loss of formation isolation and/or wellbore mechanical integrity. This in turn may result in loss of production, loss of the wellbore, pollution, and/or hazardous conditions.
Although hydraulic, thermal and/or mechanical induced stresses may be encountered in all types of wells, including those having conventional vertical wellbores, such stresses may be more likely to occur in particular types of completion configurations. For example, completions having relatively thin annular cement sheaths between pipe strings and/or between the outside surface of a pipe string and the inside formation wall may be particularly susceptible to stress-induced cement damage. Such thin cement sheaths may be encountered, for example, in conditions where open hole wellbore size is limited, yet a cemented pipe string diameter must be maximized. Examples include, but are not limited to, those cases where full length or stub liners are cemented, for example, to isolate casing damage and/or substantially eliminate formation pressure and/or fluid communication.
In other cases, a main or primary wellbore may have one or more secondary wellbores extending laterally therefrom to form a lateral or multi-lateral completion. In such cases, a primary wellbore may be vertical or deviated (including horizontal), and one or more secondary lateral wells are drilled from the primary wellbore after it has been cased and cemented. Each of the secondary lateral wellbores may be vertical or deviated, and may optionally include a cemented liner which may be tied into the primary wellbore. In this regard, secondary lateral wellbores may be drilled from a primary wellbore initially, and/or at any other time during the life of the well. Such lateral or multi-lateral completions may be particularly susceptible to stress induced cement failures for a number of reasons. For example, the juncture between the primary and secondary lateral wellbores is typically exposed to mechanical stresses induced by a large number of subsequent operations involving the running of tools through the junction point. The number of operations and exposure to stress typically increases with the number of secondary lateral wellbores extending from the primary wellbore. Furthermore, the magnitude of mechanical stress from a given operation typically increases with the angle of deviation between the axis of the primary wellbore and the a given secondary lateral wellbore.
When conventional cements are employed in lateral or multi-lateral wellbore completions, the set conventional cement is typically too brittle to withstand shocks and impacts generated by drilling and other well operations performed in the secondary lateral wellbores. Therefore, in such completions, conventional set cement compositions typically fail by shattering or cracking, resulting in loss of isolation and mechanical integrity. Potential for such stress-induced cement failure typically increases, for example, in those situations in which the internal diameter of a cased secondary lateral wellbore is designed to be as close as possible to the internal diameter of the cased primary wellbore. T
Boncan Virgilio G.
Dickerson Jimmy P.
Mueller Dan T.
BJ Services Company
Neuder William
O'Keefe Egan & Peterman, LLP
Walker Zakiya
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