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Lateral buckling mitigation design for HPHT pipe-in-pipe system is technically challenging and at times the reliability of proven buckling mitigation options may come into severe technical scrutiny for some HPHT pipe in pipe systems on the undulating seabed. The Residual Curvature Method (RCM) presents as an alternative technical option for such cases. The technique comprises understraightening in intermittent sections of the ‘as-laid’ pipeline which form ‘expansion loops’ and provide a proven, reliable and cost-effective buckling mitigation. The method was successfully implemented in Statoil’s Skuld project in 2012 and subsequently a few other projects worldwide which are all single pipeline systems. However, the RC method was not used as a buckling mitigation method for a pipe in pipe system to date to the knowledge of the authors.
Residual curvature method could be proven superior for HPHT Pipe-in-Pipe Systems to other lateral buckling methods (thanks to controlled well-developed buckles at pre-determined locations) under some favourable design conditions. This paper shows the robustness of the technique for a typical 12" / 16" HPHT pipe in pipe system with an operating pressure of 300barg and 150°C operating in a maximum water depth of 2000m as a case study. The PIP system is considered to be laid by a reel-lay method, which is amenable to inducing the residual curvature at the pre-determined RC locations during pipelay process.
The study includes the special considerations required in deploying the method on an undulating seabed taking into account unplanned buckles or spans and the necessary adjustment to be made to pre-determined buckle sites. The study includes the effects of inner pipe snaking (with residual curvature) within a near straight outer pipe due to the reeling process and its impact on the lateral buckling behaviour. Other design features that may have a significant effect on the RC method are discussed.
Islam, M. S. (Dhofar University) | Kleppe, J. (Norwegian University of Science and Technology) | Abbassi, F. (Dhofar University) | Haque, M. F. (Bangladesh Petroleum Exploration and Production Company Limited)
The endeavor of this study is to evaluate the economic potential of the Norne Field's E-Segment (a Norwegian Offshore Oil Field) under different cost structure for six different field development strategies based on the simulation results of low salinity water-flooding (LSW).
The ultimate oil recovery of the Norne Field's E-Segment is ca. 40% after employing the combination of primary and seawater-flooding as a secondary recovery technique. Therefore, there is about 60% oil is still trapped as a result of high capillary action of water. This trapped oil could be extracted by introducing a novel recovery mechanism. In this case, LSW is considered to extract this residual oil adhered to rock wall.LSW simulation studies using original wells indicated that the water injection with optimal salt concentration of 1,000 ppm TDS (total dissolved salts) or 1.0 kg/m3 yields substantially higher oil production compared to sea water-flooding. Having found that the LSW is an effective Improved Oil Recovery (IOR) technique for the Norne Field's E-Segment, the next tasks are to find the different ways to increase oil recovery using LSW followed by economic feasibility study. Six different well development plans are investigated. For example, case 1 is the base case with seawaterflooding using the existing wells. The other five cases are all LSW, with the following well configurations: (2) using the original wells, (3) using the original wells in addition to a new producing well, (4) using the original wells in addition to a re-completed producing well, (5) using the original wells in addition to a new injection well, and (6) using the original wells in addition to a re-completed injection well. Economic feasibility study has been conducted for all these six cases using Net Present Value (NPV), Profitability Index (PI), and Internal Rate of Return (IRR) methods.
Analyzing the simulation results of the above six field development plans, it has been revealed that the oil production for five LSW cases are higher than the seawater-flooding case which, in turn, result more NPV, more PI, and more IRR for LSW cases. Among the six field development cases, Case-3 has been indicated the highest cumulative oil recovery compare to other five cases and give the highest NPV. Thus, it could be concluded that the Norne Field's E-Segment is a good candidate for LSW to extract the residual or trapped oil.
In this study, LSW simulation results are found to give a favorable mobility ratio, which in turn is resulting the highest oil recovery and the highest revenue.
Islam, M. S. (Dhofar University Salalah) | Kleppe, J. (Norwegian University of Science and Technology) | Rahman, M. M. (Bangladesh University of Engineering and Technology) | Abbasi, F. (Dhofar University Salalah)
Low salinity water-flooding (LSW) is a promising Improved Oil Recovery (IOR) process in which the salinity of the injected water is controlled to progress oil recovery over conventional seawater-flooding and other EOR methods. Published laboratory studies and field test cases in the last two decades have suggested several mechanisms of oil recovery by LSW, which is still an immature area of research. However, the commercial reservoir simulators have limited capability to model LSW accurately. The principal objective of this paper is to evaluate the potential of IOR using LSW for the Norne Field's E-segment.
There is about 60% oil is still trapped as residual oil especially in the Ile and Tofte formations of the Norne Field's E-Segment even after the completion of primary recovery and seawater-flooding as a secondary recovery technique. LSW simulation is, therefore, run for a period of 18 years from 2005 to 2022 to extract this residual oil adhered to rock wall. LSW simulation studies using original wells indicated that water injection with optimal salt concentration of 1,000 ppm TDS (total dissolved salts) or 1.0 kg/m3 yields substantially higher oil production (34.13 MSCM) compared to seawater-flooding (32.95 MSCM).
With the encouraging finding of LSW, the next stage of the study is involving simulation of different scenarios. Six different cases have been investigated. Case 1 is the base case with seawaterflooding using the existing wells. The other five cases are all LSW, with the following well configurations: (2) using the original wells, (3) using the original wells in addition to a new producing well, (4) using the original wells in addition to a re-completed producing well, (5) using the original wells in addition to a new injection well, and (6) using the original wells in addition to a re-completed injection well. Case 3 indicated the highest oil recovery (50.10 MSCM) compare to other five cases. Thus, it could be concluded that the Norne Field's E-Segment is a good candidate for LSW to extract the residual or trapped oil.
In this study, LSW simulation results have shown the alteration of wettability from neutral-wet to strongly water-wet, which in turn is resulting in a favorable mobility ratio, is the most important IOR mechanism for the Norne Field's E-Segment. LSW in this case is found to give near to piston-like displacement.
The Onyx field is an undeveloped gas field located in the Poui-Teak Ridge, in the TSP acreage, offshore Columbus Basin, Trinidad & Tobago.
Fault sealing capacity is crucial in the Onyx gas field, which presents clear evidences of hydrocarbon fault leakage along a major fault. This is assessed in this particular case, in order to estimate possible hydrocarbon columns in non-drilled structures within the field. Results are compared against previously published models based on world wide data sets.
The paper approach is based on calibrating computed Shale Gauge Ratio (SGR) for a major fault in the field structure against RFT pressure data across two reservoir fault blocks. It considers Across Fault Pressure Differences (AFPD) as a function of reservoir fluid densities and its columns. An Allan diagram was built for all the major faults of the reservoir structure. In those areas where the diagram shows sand-sand juxtaposition, the relationship between SGR and AFPD is applied. A fault seal failure envelop has been derived from the data and the calibration method is described, making it possible to be applied in fields where lateral sealing faults are major controls in the reservoir trap.
This analysis highlights the likelihood for sands in adjacent fault blocks to be hydrocarbon bearing, and possible hydrocarbon water contacts have been estimated for undrilled structures. This is important for creating possible different success scenarios and for assessing risks for non-drilled blocks in the field.
This type of calibration is relevant and should be assessed on a field by field basis in order to obtain more reliable estimation of remaining potential structures in a hydrocarbon field.
The High Pressure and High Temperature (HP–HT) subsea field developments are increasingly using Pipe-In-Pipe (PIP) systems for transportation of production fluids due to superior thermal conductivity performance compared to wet insulated single pipe system. PIP systems can provide the necessary thermal insulation with very low Overall Heat Transfer Coefficient (OHTC) in the order of 0.5 to 1.0 W/m2.K whether installed exposed on the seabed or trenched and buried. An additional inherent feature of PIP systems is that they offer increased protection against third party interaction such as fishing gear and dropped object impact.
PIP system will provide a very long "no touch time" before any intervention (e.g. depresurisation) becomes necessary. This aspect can also be improved by using e.g. hot water circulating and electrical heating in order to overcome difficulties which may arise from prolonged shutdown periods.
The mechanical design of a HP–HT PIP systems is more complex than conventional single pipe system and involves consideration of additional failure modes. This paper gives an overview of the PIP system design, with particular emphasis on in–service buckling and fatigue design. Design considerations for trawl gear impact on lateral buckling and operational aspects of clad and lined pipes for HP–HT and sour service applications are also discussed.
Ammar, Ahmed (Energy XXI) | Saunders, Ross (Energy XXI) | Henry, Chuck (Energy XXI) | Wilkinson, Tim (Energy XXI) | Frismanis, Mike (SeismicCity Inc.) | Bradshaw, Mike (SeismicCity Inc.) | Codd, Jeff (SeismicCity Inc.) | Kessler, David (SeismicCity Inc.)
The Gulf of Mexico shelf has been a prolific oil and gas production region for over seventy years. With limited ability to acquire new seismic streamer data due to dense surface platforms, seismic data used for interpretation and prospect generation has been in many cases sub-optimal. However, much advancement has been made in imaging technology that has enabled us to improve the interpretation and understanding of old producing fields.
The case study presented in this paper demonstrates how the use of improved model building and depth imaging technology has led to a change in the interpretation of the salt model of Main Pass 73 (MP73) Field. A drilling program targeting the Lower Pliocene and Upper Miocene sands resulted in significant new discoveries of up dip oil and gas reservoirs, thus giving new life to an old producing field.
Many of the producing fields in the GOM shelf consists of hydrocarbon bearing sands truncated against steeply dipping salt domes. Unfortunately, in many cases the salt bodies defining the reservoir edges are not well imaged on associated seismic data, making the accurate mapping of the producing reservoir very difficult.
In the past few years, efforts have taken place to acquire new data on the GOM shelf. The newer data is mainly acquired using ocean bottom node technology which results with wide azimuth seismic data. The new data has the potential to have much better seismic resolution than the older narrow azimuth streamer data used by the industry for many years. In addition, nodes can be placed much closer to surface installations, creating better illumination in these areas.
In parallel to the development and deployment of new acquisition technology, much progress has been made in the past several years in processing and imaging technology. The main advancements include (a) the ability to construct more detailed anisotropic earth models with much more complex salt bodies and (b) the use of more accurate depth migration algorithms.
This paper covers the HPHT Gas-Condensate Exploration Well, 6406/9-1 on the Onyx SW prospect of the Norway Sea in the late spring of 2005 (Figure 1 and 2). The well test design and execution is presented in the paper, including; up front planning, job design, technology selection and review of the test results vs. the objectives for the well test. The paper also addresses how health, safety and environmental considerations were handled.
Traditional well testing methods and equipment have evolved over the years, adapting to changing requirements. This has resulted in requirements for more complex data gathering over a shorter time with much stricter environmental and safety constraints. Coupled with increased needs for more accurate reservoir data for prospect evaluation, this has put a higher emphasis on upfront planning and improved technical performance together with extensive use of advanced fluid data gathering methodologies.
This paper demonstrates how the above was addressed for the Onyx SW and how the results compared with the set goals. The application of the latest technologies in Gas-Condensate well testing was used on this job. Experiences from this were later used as the basis for other gas-condensate prospects, including those in the Russian sector of the Barents Sea.
This paper focuses in particular on Fluid Sampling, Surface Well Testing and Subsea equipment. As several service companies were involved on this particular job, we have only included some general and limited content for the other services involved.
This paper presents an innovative completion technology, fine tuned by reservoir simulations, for balancing the water injection profile into various sand formation zones in an open-hole completed injector well, increasing sweep efficiency.
Traditional injection wells often suffer from the risk of sanding in, hence sand control is beneficial or even required. Another major challenge is to achieve even distribution of the injected water into all zones along the well-bore. Injector wells are often designed to penetrate, and give pressure support to, several reservoir intervals with various permeabilities which challenges the reservoir management. Permeability contrasts, heel-toe effect, formation damage, creation of thief fractures and well bore injectivity changes need to be managed to avoid early breakthrough in adjacent production wells. Smart-well systems are highly complex and costly, and for this particular case, where raw seawater is used, the high corrosion resistance requirement was considered a show stopper.
The solution was to qualify and install special screens with integrated flow control devices, tailor-made for injection wells, and with correct nozzle sizes for this particular case. These screens were made of materials selected to withstand the corrosive environment and high rate of unfiltered water during lifetime of the well. The screens where gravel-packed to restrict annular flow and give zonal isolation, which optimizes regulation of reservoir heterogeneities.
This new technology is representing a quantum leap forward in field economics, by marrying all the benefits realized with this simple robust and reliable self-regulating injection management system.
The paper will discuss the qualification program inclusive focus on risk of erosion, plugging and corrosion. Further, the completion design of the well, with flow distribution simulations and sensitivities inclusive comparisons with actual field date is also reviewed together with economic value analysis. Future potential, applications and scenarios will also be discussed.
Urd was developed as a satellite to Norne FPSO during 2004-2005. The oil field consists of two separate structures, Svale and Stær, located 4 and 9 km from the main field. The field was put on production in 2005 and was developed with 3 subsea templates, and pipelines for oil production, water injection and gas lift (Figure 1). Norne and Urd is operated by Statoil on behalf of ENI Norge AS Norsk Hydro Production AS and Petoro AS.
The application of the special screens with integrated flow control devices for injection wells (called ICD injector) was evaluated as a part of the field development plan for Urd. Since both Svale and Stær consist of heterogeneous pay zone, the main reservoir management goals of implementing an ICD injector are:
The important feature of the ICD injector is the self-regulating effect with functions independently of surface control. If one zone is fractured during the operation of the injector and can take more water, then the nozzle in the ICD injector will prevent increased injection into this fracture. This will ensure improved water distribution, which will result in better pressure support and drainage of the oil reserves in all zones.
A total of 585 million barrels of oil had has in many cases been the sole success factor been produced from Troll by January 2001. Without the in developing resources once thought nonexistent or use of new technology and the meticulous management economically unobtainable. of the risks involved in the development project, these Looking ahead, there is an undeniable need for resources would have remained untapped forever.
In 1984 and 1985, the Skuld experimental station was remotely operated and intensively tested in North Sea conditions for 1 year. This full-scale station, simulating production from a two-well cluster, was installed diverless in June 1984 outside Bergen, Norway, at 90-m [295-ft] water depth. Installation took less than 6 hours per module because we used guidelines and a dedicated landing tool, and the 1-year intensive test confirmed the reliability of the subsea equipment. This experiment demonstrates the validity of the development scheme using the Skuld modular concept.
The first offshore production installations were adapted from exciting onshore installations to meet the new environment. A permanent effort has been devoted to the optimization of offshore production equipment and structural supports to permit economical developments in deeper water. Today the oil industry faces another challenge that requires the development of new technologies-the water depth becomes so great that the use of permanent structural support is questionable with regard to feasibility and/or economic viability. In addition, diver assistance at such water depths is risky, limited, or even impossible. Therefore, underwater technology that considers diverless procedures must be developed,
For more than 20 years, Elf Aquitaine developed a research program for underwater technology. The first step of this program, program for underwater technology. The first step of this program, the North East Grondin pilot well, led to the decision to develop North East Frigg with underwater equipment, However, this development, which was successfully completed in Dec. 1983, includes a permanent surface support located in the vicinity of the subsea production station. This permanent surface support represents an important part of the investment cost and would render smaller fields or development in deep water economically nonviable. Therefore, we initiated a program for the design, development, and reliability assessment of an underwater technology suitable for the development o, deepwater fields on the Norwegian continental shelf. This research program was named Skuld for the major Viking divinity who symbolized future and necessity.
The first objective of Skuld was to investigate ways of developing an offshore satellite field a long distance from existing surface fa-cilities without using any permanent support in the vicinity and considering the North Sea environment. Consequently, two main goals became the basis of the Skuld program: (1) to improve equipment reliability (mainly control system) to minimize the operating cost and (2) to study the subsea equipment's ability to cope with the hostile conditions of the North Sea by using diverless procedures. Therefore, Skuld constitutes an important part of the initial research program by consolidating the results of the first step and by program by consolidating the results of the first step and by extending the validity of diverless techniques to deeper water and a harder environment.
Basic Development Scheme
Design. Table 1 presents basic field data for the Skuld development. A subsea template is used as a base to drill the wells and to support the manifold. The gas produced by four underwater Christmas trees (wet type) is collected by the manifold and flows through 5 x 20-cm [2 x 8-in.] -diameter sea lines to the permanent surface facilities, where all the equipment for gas treatment. metering, and com-pression is located.The subsea station is remotely operated and controlled from the distant surface facilities by means of a multiplexed, electrohydraulic control system located on the subsea station. This control system is linked to the emergency shutdown system of the surface facilities. Electrical power and coded messages are transmitted from the processing platform to the underwater control system by a subsea cable. processing platform to the underwater control system by a subsea cable. In a backup mode, the marking buoy is installed in the vicinity of the subsea station to provide the required navigational aid and is used as the radio relay for the signal transmission. Moreover, the electrical generator located on board supplies the power to the marking equipment and to the underwater control system. Figs. 1 and 2 show the field architecture and the basic flow diagram, respectively.