Unmanned minimum facility platforms are a reliable alternative to traditional wellhead platforms or subsea installations, and the technologies enabling simpler designs have evolved. Anadarko aims to maximize immediate short-cycle value through tiebacks and platform relocations in the Gulf of Mexico. This review of papers illustrates some of the innovative solutions used in the region. In maturing oil wells, oil production is often restricted as reservoir pressure depletes. Two case studies highlight the application of two-screw multiphase pump systems in to extend well life.
Development of marginal deep water fields requires an integrated and cost-effective approach for costs minimization and production enhancement by synergies with existing surrounding infrastructures. This paper details the successful use of Integrated Reservoir and Production Modelling to unlock the development of three marginal deep water oil discoveries in synergy with an existing surrounding subsea development. A marginal field is usually defined as a field that may not produce enough net income to make it worth developing. Deep water satellites are among those, requiring important development optimizations to unlock their potential. Integrated Reservoir and Production Modelling is largely used within the Oil and Gas industry for evaluating production forecasts associated to development assumptions by modeling the fluid flow from pore to process while honoring all required subsurface to surface constraints. This paper describes how the use of such modeling approach has been used to unlock the development of these marginal oil discoveries by evaluating the value of different development concepts from stand-alone to tie-back together with standardized and under-qualification subsea technologies. The Integrated Reservoir and Production Models were made of the three reservoir dynamic models of the three marginal fields connected to the well and network production models capturing the various concepts evaluated. Three main development concepts have been tested: stand-alone, short tie-back to field X and long tie-back to field Y. For all these concepts, many sensitivities have been performed: well implementation patterns, well completion and activation, production and injection networks design including subsea boosting and surface capacities debottlenecking. Tie-back to field X has then been further evaluated to determine detailed bases of design maximizing the value of the project. Integrated Reservoir and Production Modelling has been key to enable cross-functional team work and determine the best incremental value of these marginal fields in synergy with the production of the surrounding existing field.
The various cycles which affect our oil industry have emphasized the need for detailed control of expenditure for development and production of small discoveries. However, should technical or economic conditions change, such a field may become commercial field. Marginal fields have several parameters that affect them. This includes environmental concerns, political stability, access, remoteness and, of course, the price and price stability of the produced gas/liquids. This course will describe parts of unconventional methods to develop the marginal fields which mainly focus on innovative methods and new technology in developing those marginal fields.
The various cycles which affect our oil industry have emphasised the need for detailed control of expenditure for development and production of small discoveries. However, should technical or economic conditions change, such fields may become commercial fields. Marginal fields have several parameters that affect them. This includes environmental concerns, political stability, access, remoteness and, of course, the price and price stability of the produced gas/liquids. This course will describe parts of unconventional methods to develop the marginal fields and mainly focus on innovative methods and new technology in developing those marginal fields.
Subsea oil and gas developments in the Grand Banks region, offshore Eastern Canada, require mitigation techniques to protect against iceberg keel interactions. For example, untrenched infield flowlines incorporate weak link systems designed to fail in the event of flowline snag to protect upstream and downstram assets. Even with these systems, the assumption that any iceberg contact equates to flowline failure means that flowline lengths in excess of approximately 10 km require trenching to meet safety target levels. Furthermore, all subsea wells to date have been installed in excavated drill centers to avoid contact with gouging icebergs. Based on current design practices, these mitigation measures are cost prohibitive and limit the potential for the development of marginal fields. This paper addresses conventional practice to protect against iceberg interaction and proposes alternative solutions that maintain safety, while reducing costs significantly.
Up to present, the annual iceberg contact frequency for short subsea flowline systems designed for offshore Newfoundland and Labrador has been less than the target reliability level. For longer flowlines, iceberg contact rates will be higher and the consequence of such contacts must be considered. It is possible, for example, that the pipe gets pushed into the seabed with acceptable damage to the pipe and/or localized ice failure takes place. If it can be demonstrated that a pipe could survive some impacts, it might be possible to avoid costly protection strategies such as trenching or rock berms. This paper describes physical tests conducted as part of a preliminary investigation to assess the consequence of a free-floating iceberg interacting with a flowline placed on the seafloor. Two scenarios were considered in this testing program. The first focused on understanding the local iceberg failure processes and the second evaluated the transverse flowline motion when a free-floating keel snags a flexible pipe laid on the seabed.
Despite technical challenges, these assets could be monetised with the right conditions. In the current environment, the traditional approach to development plan as well as restrictive heritage fiscal terms may result in low interest leading to ‘money left on the table’ by stakeholders. Paradigm shifts are required to create an ecosystem where all parties are incentivised to succeed. Efforts towards making economically challenging assets feasible via enabling technologies should be encouraged by all stakeholders. The authorities, operators and service providers should have a collaborative mindset and work on removing obstacles and any potential show stoppers.
FIELD ‘A’ Project is presented as a low cost development concept for marginal oil field. The development concept consists of wellhead platform with a full well stream evacuation scheme through a flexible flow line to FPSO for further processing and subsequently for export. The unutilized associated gas is flared. As a part of cost reduction strategy and incentive, the Host Authority has approved a new contract model and technological approaches for implementation.
FIELD ‘A’ Project is undertaken and monetized via a new approach of marginal oil field development under the Risk Service Contract (RSC). The uniqueness of the FIELD ‘A’ development concept is the technological introduction of re-locatable type fixed asset using Suction Pile Technology (SPT) for jacket installation thus allowing it to be transported and utilized at other potential marginal field within the asset design life. SPT is a traditional jacket with integrated suction pile foundation, which triggered significant benefit and long term cost reductions in the fabrication and offshore installation.
The 1100 MT jacket is designed using suction pile technology that enables the platform to be relocated to other potential marginal field. SPT is proven to be a highly efficient and very swift concept where the jacket offshore installation campaign can be successfully executed in less than 24 hours as compared to the conventional jacket installation, which require several days of pile driving. Fabrication costs are reduced significantly since no requirement on the pile sleeves, catchers, centralizers, mud mats, and leveling pad eyes. Substantially, SPT jacket is proven to be that of one of the most cost effective in comparison to other re-locatable type offshore mobile facilities such as MOPU and MOAB. SPT is also integrated with scour protection; hence no seabed preparation or rock dumping is required. Therefore, the offshore campaign for SPT would promote lower installation cost, improved schedule and most importantly safety. In conclusion, the jacket with integrated suction pile foundation promotes and accordingly justifies the development of marginal field.
In the current environment of low oil price, developing a new marginal field in such a way is necessary so as to maintain or improve the overall economic of the project. This fit for purpose and hybrid SPT concept with a rigid substructure that can be easily relocated is definitely worth to be implemented.