Not Applicable.
The invention relates to methods for developing offshore oil and gas fields. One of the biggest challenges in the development of oil and gas fields has been the fact that the reservoirs found in the fields can not be observed except through indirect means, which introduce a large amount of conjecture in the assessment of the actual in-place conditions. In deepwater offshore fields, conventional methods used to mitigate risks in the development have proven problematic, forcing a development regime where the investments are much larger and yet have to be made with less information than is traditionally collected prior to decision making.
Investments involved in the development of oil and gas fields are substantial and subject to high levels of risks. The development of an oil and gas field has generally involved significant up-front data gathering, in order to estimate the risks involved in the project, and engineering, in order to better specify the final delivered product and therefore the costs involved. The process for bringing a field into production involves a number of sequential definitional steps.
Although each company has small variations, the steps involved in the typical development processes 10, which are shown in
Once the initial exploration well has been drilled and some quantity of hydrocarbons has been identified, the appraisal drilling phase 14 starts. In this phase, several additional wells are drilled to delineate the reservoir and gain reservoir information. As the wells are drilled, various logging and testing operations can be performed in order to establish reasonable information to put into the reservoir models, which are then used for better understanding of the various important parameters.
Once the reservoir has been appraised, a plan for development of the field is defined 16. The plan may comprise identification as to the number and location of wells to be drilled, what kind of surface facilities, what type of riser systems, and what export means (pipelines, tankers, etc.) will be used. These plans are all based on the reservoir information that is available, which as discussed above, may be incomplete or inaccurate. Once defined, the plan for development is executed 18, which comprises the procurement and construction of equipment and systems needed for the project. Once the necessary equipment is in place, the field can be operated 19.
During the operation of the field 19, conditions within the field may change or may not be exactly what was predicted during the evaluation and planning phases. Because most of the equipment and systems specified for the field were designed and built to operate under a specific set of conditions, any change to these conditions may cause the equipment to operate at less than optimal efficiency.
Although the processes and their associated faults discussed above are generally used for all fields regardless of location or technical complexity, there are a number of additional factors in the high pressure, high temperature, sub salt portion of the deepwater Gulf of Mexico that make these processes particularly problematic. One of these factors is that, in the deepwater Gulf of Mexico, the seismic technologies are significantly less reliable due to the extreme depths of the targets combined with the complications involved in seismic data acquisition through the salt canopy that covers much of the acreage in the deepwater Gulf of Mexico. Deficiencies in the seismic exploration are often made up for by drilling more exploration wells, but this is not an attractive option because the costs and complexity of drilling a well in these deepwater regions are significant.
Thus, the embodiments of the present invention are directed to methods for developing offshore fields that seek to overcome these and other limitations of the prior art.
In one embodiment, the method of the present invention comprises deploying a lead drilling and production vessel to an offshore field to drill and complete at least one well. Production from the at least one well is initiated and evaluated. A secondary production vessel is selected based upon the evaluated production and is deployed to the offshore field to replace the lead drilling and production vessel and support production of the at least one well.
Thus, the embodiments of present invention comprise a combination of features and advantages that enable the development of an offshore field to be performed in a more flexible and economical manner. These and various other characteristics and advantages of the present invention will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention and by referring to the accompanying drawings.
For a more detailed understanding of the present invention, reference is made to the accompanying Figures, wherein:
In the description that follows, like components are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness.
As discussed above, current offshore field develop processes are aimed at minimizing overall project cost so as to minimize risk if the project fails and maximize profitability if the project succeeds. As an alternative, embodiments of the present invention seek to reduce risk by minimizing project costs that must be committed prior to the first few producing wells coming on line. Several major benefits arise from this modification of procedures, including delaying the commitment of funding until after the necessary information has been acquired and using initial production proceeds to offset project expenditures as the development expands.
Referring now to
For example, as shown in
If the lead vessel does not have the capabilities to support the operation of the field a secondary production vessel is selected 40, based upon the evaluated production from the at least one well and the operation plan. The lead vessel would then be replaced by the secondary production vessel to support production of the at least one well and the ongoing operation of the field 42 in accordance with the operation plan.
If the field is to be operated as a large field 44, the lead drilling and production vessel could be used to drill additional wells and them be replaced with a large production and completion unit. If the field is to be operated as a medium-sized field 46, the lead drilling and production vessel could be used to drill additional wells and them be replaced with a medium-sized production and completion unit. If the field is to be operated as a small field 48, the lead drilling and production vessel could be replaced by a small production unit. If the field is to be operated as a very-small field 50, the wells drilled could be tied back to a remote platform.
During the operation of the field, the production is evaluated and the plan for operation can be modified if desired. If desired, a follow-on production vessel can be deployed to the offshore field 52 to replace or support the secondary production vessel in the development and/or production of the field. For example, an additional drilling vessel 54, an additional production vessel 56, an additional drilling and production vessel 58, or an additional service platform 60, such as a water injection unit, can be deployed to support or replace the secondary production vessel. Additionally or as an alternative, the secondary production vessel may be upgraded or modified to more efficiently manage the operation of the field.
One key to the efficient and cost-effective implementation of the development methods described herein is the use of standardized component designs that can be adjusted to a range of conditions and have modular components that allow for the separation of systems architecture such that the components that must be purpose-designed and built can be isolated. The systems would also preferably include interfaces that allow groups of components to be combined as generic pre-designed, reusable assemblies that allow for individual components to be removed and replaced as needed. The modularity and interchangeability would apply to small components, such as an individual valve manifold, to larger components, such as the floating system itself being able to be replaced by another floating system. The standardized and modular components and systems may include elements of the following: mooring lines; mooring systems designed for fast installation of anchors; riser components; hulls; topsides modular structures; subsea wellheads; subsea controls; subsea gas storage; and export interfaces.
One such modular system is a modular installation vessel that can be configured for use in the installation of several of the sub-components and systems. One such modular installation vessel is described in U.S. patent application Ser. No. 11/739,141, which is hereby incorporated by reference herein for all purposes. When planning a large project, the capabilities of the available installation vessels are very important because there are very few vessels that can do large deepwater projects. Any one large market will have only one or two large installation vessels available at a time. Therefore, all projects in that geographical area must be designed around the capabilities of that vessel that will typically drive the structural design of the topsides deck, the systems used for maneuvering the hull, and the components of both the mooring and riser systems.
One example of a modular installation vessel is shown in
In one configuration, vessel 100 is especially well suited for the float-over installation of a topsides 124 onto a partially submerged semi-submersible hull 126, as is shown in
Referring now to
Another vessel used with the development methods described herein is a lead drilling and production vessel that has the capability of drilling, completing, and producing at least one well. In one embodiment as is shown in
The purpose of the lead drilling and production vessel 260 is to drill a few wells and start production immediately for the purposes of accelerating cash flow to offset expenditures as well as for the purposes of starting the reservoir evaluation process using data from production and downhole sensors. This lead vessel can be leased out for a given period of time, where the length of the lease is intended to cover at least the period required to drill the initial wells and produce for a period of time required to ensure the reservoir models can be properly updated and then to select the vessel that will be used to produce the field. The lead drilling and production vessel 260 is therefore designed to be able to drill a well 264 while receiving production from a vertical riser system 266. The lead drilling and production vessel 260 may use surface pressure control equipment, such as a surface BOP 268 and a surface (dry) tree 270, to provide pressure control at the rig, therefore reducing the amount and complexity of subsea equipment and simplifying maintenance. The surface pressure control equipment may be supplemented by additional seafloor shutoff valve 272, which could be driven using an independent control system 274.
In many instances, the lead drilling and production vessel will move from a project once the field is initially evaluated and be replaced by a secondary production vessel. The secondary production vessel may be any one of a series of platforms, such as those shown in
The modular topsides units can be used to ensure that the changing process needs of a specific field can be accommodated. Modifications should be expected both for a single field, as the reservoir understanding changes, as well as when the vessel relocates from one field to another. Referring now to
Referring now to
The replacement of a single piece of equipment is provided for by locating the equipment that is most likely to need replacement or modification on the outside of the facility or in areas that are most accessible by cranes and constructing the individual module packages with an open space frame arrangement to enable easy access to equipment. The structural connections between the modules and the base structure are preferably configured to allow a single module to be entirely replaced while offshore or in a shipyard. An individual module can be lifted using a derrick barge or by a crane that is mounted on the base structure and moved to a barge or other location. In some cases, the desired modifications may be so major that it may be more convenient to remove the entire unit and move it to shore before reinstalling it on the floating system. This can be done by ballasting the vessel down and floating the topsides off onto a modular installation vessel.
Another important component of an offshore field development is the system used to export the hydrocarbons produced from the offshore field to a land-based refinery or other production facility. Referring now to
In certain situations, such as the early stages of production, subsea oil and gas storage tanks 218 are provided to store produced oil and gas. A surface buoy 220 is provided to export the stored oil and gas to offloading tankers for shipment. The subsea storage tanks 218 are modular units that are connected to a main export pipeline 222 with valve branches 224. Thus, if more storage tanks can be added as necessary, providing a fully scalable system.
Referring now to
Referring now to
The various sizes of floating vessels and platforms described above are designed to use the same line size and mooring systems, although larger vessels may require more mooring lines than smaller vessels. Using this system, if a larger vessel were to be replaced by a smaller vessel, most of the mooring system could remain in place. Because expected mooring loads are site dependent, a particular vessel may need more mooring lines at one site than at another. For this reason, the vessels can be designed to accommodate the number of lines that are needed in the worst anticipated design conditions, although fewer lines may be deployed on a given application.
The previously described systems, as well as other systems known in the art, may be used in the development of a field as described in reference to
Once the lead drilling and production vessel is in place, a drilling riser is run and the first well 320 is drilled from the lead drilling and production vessel using the drilling riser. Once well 320 has been drilled, but not completed, the top hole of the second well 322 is drilled to the point that the wellhead can be set and the drilling riser is then parked on the wellhead of the second well. A completion riser is then run and connected to the first well 320 so that the first well can be completed. The drilling and completion risers can be run independently or the completion riser could be run inside of the drilling riser. Once the first well has been completed, it is brought into a production mode by running a production vertical tubing string from the vessel to the first well 320. On the surface, the production tubing is terminated in a surface tree, which allows for primary shutoff. At this point, production can commence from the first well 320. Once the first well 320 has been brought on production, the lead drilling and production vessel drills, completes, and brings into production the second well 322.
As illustrated in
At this point, updated well and field development plans can be developed based on the reservoir conditions as measured on location rather than as postulated based on sparse and questionable data. The updated reservoir information can then be used as input into the well planning and subsequent facility design data that can be used to design the facility that will ultimately take the drilling and production unit's place on location. Once the reservoir conditions are better understood, the field development planner may wish to pursue the field development using one of a variety of methods.
In one scenario, the field is very small and intervention does not seem to be justified but production properties allow for a long distance tieback. In this case, the field will be turned into a two well tieback, as shown in
In another scenario, as illustrated in
If the field proves to be somewhat larger, it may be desirable to drill a limited number of additional wells 332, as are shown in
The storage facilities are removed and a small to medium diameter pipeline 334 is connected to the modular export system. An additional distribution box 336 and the additional jumpers are installed on the seafloor prior to the commencement of drilling activities. The drilling and production vessel is used to drill the additional wells. Installation of these additional components can be accomplished either using the vessel's surface lowering equipment or alternatively, the installation vessel can be brought back to location to perform these operations. Fewer mooring lines may be required for this application because of the smaller size of the production vessel as compared to the lead drilling and production vessel and therefore any unnecessary lines can be removed by the installation vessel.
In another scenario, as illustrated in
In fields that may utilize a large production unit, it may be desirable to commence the upgraded production prior to the completion of drilling. In this case, the production unit can be built without any drilling rig at all and can be positioned near the lead drilling and production unit, which will be kept on station. The lead drilling and production vessel will be responsible for only the drilling program and the large production unit will be responsible for all other activities. In this case, the control systems distribution boxes will remain on the seafloor, but the SUTA's and control umbilicals will be run from the production unit rather than the drilling unit. The MES will remain in its original location and can have additional large diameter output pipelines added and its input jumpers relocated from the lead drilling and production vessel to the production unit. Further, existing wells can also be connected to the large production unit. A new mooring system will have to be installed for the large production vessel.
In combination with any of the scenarios listed above, additional reservoir needs may be identified during the course of production, such as the need for additional water, gas, or chemical injection, or any variety of equipment. In this case, this additional equipment can either be added to the existing facility or it could be deployed on a new small unit, similar in size to that noted above as the small production vessel. Since this equipment can be added later, it does not need to be designed into the initial development plan, therefore deferring capital requirements until the information is available.
The skilled practitioner will note that the flexible components and technologies that interact in this system can be used in a wide variety of ways to adjust to evolving reservoir understanding and that they are capable of addressing nearly all practical applications that are found in deepwater field development with relative ease. The system as presented is therefore a flexible, extensible architecture for field development that allows modification of the existing decision making paradigm. The methods described herein provide a separation of the design of the equipment that is on the seafloor and the equipment that is on the surface. It is therefore much simpler to contemplate the redeployment of the facility as well as the replacement of the initial facility with a more appropriate unit.
The preferred embodiments of the present invention relate to apparatus for the development of offshore oil and gas fields. The present invention is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the present invention with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results.
The embodiments set forth herein are merely illustrative and do not limit the scope of the invention or the details therein. It will be appreciated that many other modifications and improvements to the disclosure herein may be made without departing from the scope of the invention or the inventive concepts herein disclosed. Because many varying and different embodiments may be made within the scope of the inventive concept herein taught, including equivalent structures or materials hereafter thought of, and because many modifications may be made in the embodiments herein detailed in accordance with the descriptive requirements of the law, it is to be understood that the details herein are to be interpreted as illustrative and not in a limiting sense.
This application claims priority to U.S. Provisional Patent Application No. 60/869,173, filed Dec. 8, 2006, and titled Methods for Development of an Offshore Oil and Gas Field, which is hereby incorporated by reference herein in its entirety for all purposes.
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