TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMultilateral technology offers the oilfield many advantages since it can deploy a completion system that can mechanically connect several lateral wellbores to a parent wellbore and will allow selective or commingled production. In most cases, these capabilities can provide more cost-effective well construction since reservoir exposure from one wellbore is increased. These advantages are particularly beneficial in offshore and deepwater environments where slot and/or subsea templates are limited, and rig costs are substantially higher. Because of the flexibility of this technique and its capability to offer various production options, it helps to mitigate the risks previously associated with directional/horizontal wells in new field developments as well as in revitalization of mature fields. Because of continual improvement in drilling techniques and the increase in field success, multilateral technology continues to gain in popularity; however, as with all completion techniques, it must be remembered that existing completion options must be evaluated for each case, and if needed, adapted to meet specific reservoir objectives and concerns. This paper will focus on considerations, applications, and benefits of specific tool configurations developed for interfacing sand-control fracturing stimulation with multilateral technology. The techniques discussed include existing, modified, and conceptual completion methods that can be deployed into multilateral field-development strategies. The strategies address window selection, junction isolation, fluid loss, debris management, and lateral accessibility. Several completion sequences, which include a new Technology Advancement for Multi-Lateral (TAML) level 4 single-trip, gravel-pack methods and installation of expandable screen technology, will also be presented.
Multilateral technology offers the oilfield a completion system that mechanically connects one or more lateral wellbores to a parent wellbore and allows selective or commingled production. These capabilities usually provide more costeffective well construction since reservoir exposure from one wellbore is increased. In offshore and deepwater environments where slot and/or sub-sea templates are limited and rig costs substantially higher, these advantages are even more beneficial. Because of the flexibility of this technique and its capability to offer various production options, it helps to mitigate the risks previously associated with directional/horizontal wells in new field developments as well as in revitalization of mature fields. Continual improvement in drilling techniques and the increase in the number of field successes using multilateral technology have continued to increase its popularity; however, as with all completion techniques, it must be remembered that existing completion options must be evaluated for each case, and if needed, adapted to meet specific reservoir objectives and concerns. This paper will focus on interfacing sand-control fracturing stimulation with multilateral technology. The techniques targeted include existing, modified, and conceptual completion methods that can be deployed into multilateral field-development strategies. The strategies address window selection, junction isolation, fluid loss, debris management, and lateral accessibility considerations along with the applications, and benefits of specific tool configurations recently developed. Several completion sequences, which include a new Technology Advancement for Multi-Lateral (TAML) level 4 single-trip, gravel-pack methods and installation of expandable screen technology, will also be presented. Introduction The benefits of multilateral technology have been well documented around the world as a cost effective alternative to accessing oil and gas reserves. To date, the bulk of these installations have occurred in naturally fractured carbonate reservoirs as well as poorly consolidated sandstone reservoirs. In either scenario, the lateral borehole typically is drilled horizontally so that maximum reservoir exposure can be obtained. Slotted liners or sand screen completions have been very effective for borehole support and/or sand-control devices when deployed in uniform sandstone reservoirs,1 whereas openhole completions are commonly used in carbonate reservoirs with natural fractures. Fracture stimulation and advanced sand control completion applications can also be implemented into multilateral well planning strategies. Low-perm carbonate reservoirs can be effectively stimulated using traditional stimulation designs normally performed in single wellbore applications. The junction isolation tool configuration will vary and depend predominately on the TAML classification of the junction as well as whether the stimulation job is pumped down the casing or the tubing work string. In addition to isolating the junction from the stimulation-treating pressure, the tool configuration should also have capability to provide well control and zonal isolation. This will allow multiple lateral legs to be individually stimulated from a single parent bore and will eliminate the need for kill-weight fluids after each zone is stimulated and unloaded. In sandstone reservoirs that require gravel packing or fracand-pack applications, the completion tool configuration for the mainbore and lateral completions will differ. The mainbore completion below the junction can normally deploy traditional sand-control equipment.
The ever-increasing scope of environments into which today's oilfield activities have moved require many more extremely complex operations to be used. Because of the added complexity and the increasing costs of operations, especially in subsea environments, considerable upfront planning time to develop the ‘optimal’ completion design must be spent. Operators realize that once a completion strategy is set and acted upon, any deviation from the original plan can result in significant cost increases. It has been the immediate and future costs resulting from initial planning errors that have driven operators to seek more efficient and less complex completion methods that will provide greater assurance that goals will be met. In developing well completions, the design focus usually is performed in steps. First, the lower-completion equipment and sand-control service tools that ensure zonal stimulation, fluid-loss control, and zonal isolation are considered. Then, the design moves to the upper completion design that includes all equipment that transports hydrocarbons to surface. A significant upper-completion issue has been the difficulties experienced in spacing out and landing the hanger and tubing systems. Spacing-out operations are a significant part of land, shelf, and subsea completions; however, this paper will focus on the subsea arena. The growing need for more efficient systems for spacing out in deepwater arenas has resulted in the development of several new system configurations and completion components that will be discussed in this paper. Of primary interest is the long-space-out telescoping joint, which helps to resolve many of the issues experienced when landing the hanger and tubing systems. Introduction Completion costs are a critical factor when determining the financial returns that can be expected from an oil and gas investment. This factor becomes even more paramount in situations where operating costs are anticipated to be high, such as in subsea environments, where reserves are marginal, and/or where the environments are such that completion problems are more likely to occur. Safety-first, efficient practices are the primary concerns for most completion methods, and one critical area in completion practices is the spacing-out or landing of tubing hangers. This process involves installation of the production string and associated components of a particular length within a certain measured-depth window. In land, inland water, and on shelf applications, the production tree and hanger (the production tubing support mechanism) is on surface, which allows for an easier process for installing the aforementioned equipment (Smith et al., 2009) (Clarkson et al., 2008) This paper discusses the history of space-out methods and will present a long-space-out telescoping joint specifically designed to resolve subsea space-out issues. This telescoping joint is designed to collapse in response to a non-shearing compressive load, after landing a production seal assembly into a sealbore packer below. After the joint collapses, the production tubing can be lowered to land the subsea tubing hanger into the subsea tubing-head spool. Planning The hardware needed to manipulate, regulate, produce, and transport oil and gas to surface is designed during the completion planning process. This process as well as the sand-face completion planning requires a substantial amount of time. Unfortunately, while much thought and effort are dedicated to upfront and intermediary practices, the process required for finishing the completion; i.e., the landing string, often does not receive the same consideration.
A major operator with two large projects in Africa has been using a unique subassembly design, called the dual-isolation assembly (DIA), positioned on the bottom or toe of an open hole stand-alone screen (SAS) completion. The main objective of the DIA is to enhance the circulation process for washdown capabilities and provide efficient management and removal of the filter cake for the subsequent improvement of injectivity rates by lowering formation skin values on the injector wells. After providing high-rate washdown through the float shoe at the toe of the completion, the DIA provides a means of circulating a filter cake removal treatment for the open hole. Once the filter cake treatment has been circulated sufficiently, the service tools are retrieved from the completion to surface. For an injector well, the flow path into the formation would be through the sand-control screens and the float shoe from the inside. Since the float shoe incorporates spring-loaded valves that would normally open during injection and close when pumping stops, it is beneficial to lock the valves out of service to prevent long term spring fatigue that could cause the valves to remain open at some point during the life of the well, allowing flow back of formation material inside the screens. After treatment of the open hole, an additional function of the DIA is to close the barrier isolation valve to isolate the formation while the filter cake treatment is activating. As a continuation of an earlier paper (Roane, et al. 2018), the DIA has met all expectations on all 19 wells where it has been implemented in Africa. Due to enhanced procedures, the mechanical skins have averaged 2.5 and injectivity indices have averaged above 140 (B/D/psi) on these wells. Installation times have continually improved during the project due to following best practices. In addition to fulfilling the requirements of these standalone screen (SAS) completions, the DIA design addresses other potential challenges, such as the prevention of hydraulic locks and formation swabbing, which can be detrimental and problematic to open hole completions. Other characteristics of the DIA that benefit open hole management were realized during the course of the project, such as the capability of the DIA to wash through the interior of the isolation barrier valve prior to closing the valve. Once closed, the valve can be re-opened and re-closed as required. An important aspect of the physical attributes of the DIA that benefits logistics and running speed of the completion is its compact design allowing it to be completely assembled in the shop and shipped to location, such that it is a single pickup and makeup on the rig floor. This benefit has been exhibited by continual improvement in completion installation times throughout the project.
The ever-increasing scope of environments into which today's oilfield activities have moved require many more extremely complex operations to be used. Because of the added complexity and the increasing costs of operations, especially in subsea environments, considerable upfront planning time to develop the 'optimal' completion design must be spent. Operators realize that once a completion strategy is set and acted upon, any deviation from the original plan can result in significant cost increases. It has been the immediate and future costs resulting from initial planning errors that have driven operators to seek more efficient and less complex completion methods that will provide greater assurance that goals will be met.In developing well completions, the design focus usually is performed in steps. First, the lower-completion equipment and sand-control service tools that ensure zonal stimulation, fluid-loss control, and zonal isolation are considered. Then, the design moves to the upper completion design that includes all equipment that transports hydrocarbons to surface. A significant upper-completion issue has been the difficulties experienced in spacing out and landing the hanger and tubing systems. Spacing-out operations are a significant part of land, shelf, and subsea completions; however, this paper will focus on the subsea arena.The growing need for more efficient systems for spacing out in deepwater arenas has resulted in the development of several new system configurations and completion components that will be discussed in this paper. Of primary interest is the long-space-out telescoping joint, which helps to resolve many of the issues experienced when landing the hanger and tubing systems. IntroductionCompletion costs are a critical factor when determining the financial returns that can be expected from an oil and gas investment. This factor becomes even more paramount in situations where operating costs are anticipated to be high, such as in subsea environments, where reserves are marginal, and/or where the environments are such that completion problems are more likely to occur. Safety-first, efficient practices are the primary concerns for most completion methods, and one critical area in completion practices is the spacing-out or landing of tubing hangers. This process involves installation of the production string and associated components of a particular length within a certain measured-depth window. In land, inland water, and on shelf applications, the production tree and hanger (the production tubing support mechanism) is on surface, which allows for an easier process for installing the aforementioned equipment (Smith et al., 2009) (Clarkson et al., 2008 This paper discusses the history of space-out methods and will present a long-space-out telescoping joint specifically designed to resolve subsea space-out issues. This telescoping joint is designed to collapse in response to a non-shearing compressive load, after landing a production seal assembly into a sealbore packer below. After the joint ...
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