Deepwater Facility Selection

This paper explores and discusses the interplay between field development and lifecycle reservoir management and the selection and operation of dry or wet tree host systems for the development and production of deepwater oil and gas fields. Drawing on insights from recent Shell deepwater projects, the selection criteria related to development and reservoir management are highlighted and discussed to portrait the advantages and limitation of the two different host concepts. The paper does not attempt to expand on the engineering and construction elements of either option. Introduction Globally production from deepwater fields contributes over 5mln barrels of oil per day of total production which is expected to significantly grow in the coming years. By the end of decade production from recent discoveries, in-appraisal projects and those projects currently in the construction phase are expected to grow global deepwater production to 8 - 10mln barrels of oil per day. Over the next five years it is anticipated that the global deepwater industry will spend in excess of USD$250 billion in capital investments. In deepwater it is common for approximately one third of the initial capital investment to be related to the host system. The host serves among other purposes as the key well/subsea system tie-in point, support structure, production processing system, (in some cases) drilling operations and accommodation for crew. Selection of the host concept is critical and is dependent on a robust understanding of the many upfront development drivers. The host is ultimately the key linchpin in the overall development system and is critical to deliver a solution which maximizes economic value over the life of the project, provides a degree of mitigation against key reservoir and production uncertainties, which are inherent in deepwater developments, along with providing flexibility to capture any potential future production upsides that have been identified in the proximal development location. On this basis, perhaps the most critical and important analysis required during the initial phase of a deepwater oil and gas appraisal/development project is the identification of those aspects of the opportunity which drive the project scope and the project value proposition. Correctly identifying these " key drivers" upfront lays a solid foundation from which subsequent major project decisions related to (a) selection of an integrated development concept, (b) approach to the project definition phase and (c) project execution model, can be taken. Successful developments identify both the " key drivers" and their " interplay" early in the development process and continue to revisit this framework at key decision points as the project matures in order to test both validity and potential impacts on these decisions. Both the identification of key drivers and the subsequent project decisions they impact play firmly into the eventual approach adopted for production operations - the phase of the project where the production value is actually realized. Failing to develop a robust understanding of the key development drivers during the appraisal and feasibility phases of a project can result in major recycle and project delays, or worse poor concept selection decisions which inhibit the delivery of production and ultimately cash flow/value from the asset in the future. One of the key, if not most important, decisions related to deepwater host selection is whether to adopt a dry or wet tree system. Both systems offer distinct advantages and disadvantages depending on the context of their application in developing deepwater petroleum resources. Clearly, the decision on a dry versus wet tree system cannot be taken in isolation and should be taken in the context of the overall development system evaluation from the reservoir in the subsurface, preferred recovery mechanism, reservoir location and well placement preferences, well design, subsea equipment, processing requirements, full life reservoir management requirements and metocean/structural design considerations of both host and riser systems.

Accumulated oil production from the Troll field offshore Norway will reach one billion barrels of oil in the spring of 2005. At 315-340 meters water depth, Troll is an oil and gas field with approximately 1,700 billions Sm3 of gas and four billion barrels of oil in place. Troll consists of two main structures, Troll East and Troll West, the latter divided into an oil and gas province. The oil is located primarily in Troll West in thin oil layers of 4-27 m. This article describes how the Troll West field has been developed from a gas field with no commercial oil to a gas and oil field with accumulated production surpassing one billion barrels of oil during the spring 2005. Introduction This article describes the multi-disciplinary success story of the Troll West oil and gas field. Originally, the Troll field's thin oil layer of 4-27 m thickness was considered to have no commercial value. The development of horizontal drilling technology combined with early testing and oil production from a floating platform (FPSO) led to the conclusion that Troll West oil could be commercially produced. The most productive part of the field is the Troll West Oil Province (TWOP) with 22–27 m oil thickness. It was first developed by the installation of five subsea clusters and the Troll B FPSO in 1995. Drilling and production performance led to further development of the even thinner oil layers (4–14 m) in the Troll West Gas Province (TWGP), and installation of the separate Troll C platform, which began producing in 1999. The Troll field is one of the largest subsea developments in the world with 107 wells currently in operation. Increased oil recovery from the thin oil layers in Troll West has been possible by gradually increasing the length of the horizontal sections and introducing multi-lateral wells to reduce cost and increase the sweep area. Advanced drilling and completion technology have been developed and implemented. Seismic and geological methods determine the location of the high-permeable sands with high accuracy. The drilling and completion operations have been significantly more efficient, resulting in a higher drainage area per invested capital. Continous production drilling with up to four floating drilling rigs has been carried out since production start in 1995. More than 30 multi-branched wells with zonal control are in operation. Five three-branched, two four-branched and one five-branched well are currently in production. Figure 1. The Troll Field is located some 80 kms west of Bergen, Norway. (available in full paper) The Troll Field The Troll field is located some 80 kilometers west of Bergen, off the coast of western Norway. The water depth is 315-340 m. The Troll field consists of Troll East, mainly covered by production license 085, and Troll West, mainly covered by production license 054, see Fig. 1. The Troll license partners are:ConocoPhillips Norge 1.62374 %Total E&P Norge AS 3.69096 %A/S Norske Shell 8.10145 %Norsk Hydro Produksjon AS 9.77914 %Statoil ASA 20.80471 %Petoro AS (Norwegian state) 56.00000 %

Different equipments combined compose an offshore petroleum production system. Several development alternatives are available for a given offshore petroleum field. The selection of the most suitable system for a given scenario depends on field development characteristics and strategies such as its geographical location, water depth, environmental conditions and knowledge about similar systems already selected and in use for oil and gas production and available infrastructure in around. For the purpose of field production system design a database with types of production platforms, mooring systems, subsea equipments, reservoir main characteristics, type of wells and lifting processes is fundamental. Today, offshore petroleum reservoir production is more and more complex due to several variables involved and requirement needed to meet deep and ultra deep water depth, pre-salt petroleum with aggressive fluid characteristics, fields in remote areas and other environmental issues. Large fields in deep and ultra deep water are particularly challenging due to little availability of suitable platform types, among known concepts such as floating, production, storage and offloading unit (FPSO), semisubmersible, spar and tension leg platform (TLP). In the present paper, a database for worldwide offshore petroleum systems in use has been elaborated by searching data available in the literature. The database is organized for more than three hundred platforms distributed on more than four hundred different offshore oil fields. To serve as a basis for the conceptual design of a field production system, this database contains information such as type of the platform, field location, water depth, days for the first production, type of well, completion, mooring system, riser and offloading system. This information is structured for different water depth and environmental condition, for each field. From this database, analysis has been conducted for distribution of each type of platform by worldwide region, distribution of each type of platform by the offshore field by region, among others analysis. Concept of Utility Functions are applied to represent technological trends and to be helpful in the process. Among the results, a preference for FPSOs and semisubmersible was observed in Brazil offshore, semisubmersible, TLPs and Spars in Gulf of Mexico. In Europe, particularly the North Sea, FPSO, semisubmersible, and few TLPs have been found. In West Africa, most of the field production is based on FPSOs, although some semisubmersible and TLP could be observed. Similar analyses were conducted in other regions. Results and discussions show preferences regarding technology selected by each region, region historical data, and growth of water depth in different fields.

A study was conducted in November 2000 for the United States Department of Interior, Minerals Management Service (MMS) to identify and review state-of-the-art technologies for removing large offshore platforms located in deep water. Platforms emphasized on in this report were located in the Pacific Outer Continental Shelf Region (POCSR); comparisons were made to similar Gulf of Mexico platforms. For this study, deepwater platforms were defined as those with jacket weights exceeding 10,000 short tons located in water depths exceeding 400 feet. Three POCSR platforms (Hidalgo, Gail and Harmony) were selected to encompass the range of decommissioning conditions and to provide a thorough review of issues related to removing deepwater offshore structures. The water depths considered range from 430 feet to 1,198 feet. Specific areas of technology reviewed included lifting, transportation, disposal, and explosive and non-explosive severing techniques. The three removal methods evaluated (using the best technology currently available) were Complete Removal, Partial Removal (reefing in place) and Remote Reefing (reefing off site). Decommissioning cost estimates were prepared for the selected platforms and removal methods, including an evaluation of cost sensitivity (risk) issues and the cost of alternative technologies. Also assessed were environmental and human safety risks for current and evolving decommissioning technology. Specific recommendations were provided for industry and federal/state support for future developments. Introduction The overall goal of the MMS study was to determine and examine the issues relevant to decommissioning deepwater platforms and to quantify them in the context of economics, risk, and available technology. The following specific goals were achieved in this study:Develop decommissioning plans for selected POCSR deepwater platforms using the best technology currently available.Prepare decommissioning cost estimates for selected platforms and cases, including an evaluation of cost sensitivity (risk) issues and the cost of alternative technologies (i.e., explosive versus non-explosive severing methods).Assess environmental and human safety risks for current and evolving decommissioning technology.Provide a review of the state-of-the-art in decommissioning technology for: lifting, transportation, and disposal; explosive and non-explosive severing techniques.Prepare specific recommendations for industry and federal/state support for future developments. Scope of Work. The scope of work for the study consisted of selecting platforms to be evaluated; selecting and evaluating removal technology; developing decommissioning plans and cost estimates; analyzing safety and environmental issues; and reviewing and describing other removal technologies, their current development status, and prospects. Project Issues Offshore platform decommissioning is a challenge under any circumstances in terms of planning and executing the work in an environmentally sensitive, safe, and economical way. Regarding large deepwater platforms in the POCSR, this is particularly true. Among the issues that must be faced are: Lack of Local Infrastructure. There are currently no derrick barges of significant capacity or other types of major marine construction equipment based on the West Coast, and none are likely to be in the foreseeable future. Additionally, there are currently no onshore facilities in California (or Mexico) capable of accepting jackets or topsides of these sizes, even in small pieces.

Production techniques and designs have been developed to take full advantage of the unique dynamic characteristics of a Tension Leg Platform (TLP). The application of the information presented in this paper could be used to economically develop deep water reservoirs considered to be marginal if conventional fixed platforms were used. Data obtained in this development program indicates that the production risers can remain connected under all environmental conditions that the TLP would experience. Included are graphs, specialized hardware designs, sketches of special operating techniques and TLP performance data. INTRODUCTION For many years, the petroleum industry has developed offshore production from fixed platforms. Initially these platforms were installed in shallow water (<100'). Over the years, fixed platforms have been used in ever increasing water depth and have established a history of proven performance. In 1977, Shell Oil Company began installation of the Cognac platform offshore Louisiana in 1025 feet of water. Deep water fixed platforms are expensive. Only large and prolific reservoirs can be considered for development using a fixed platform in deep water. Development of comparatively small reservoirs or those located in water depths beyond the economic limit of a fixed platform require alternate production concepts. One alternative that has been considered is a completely submerged seafloor production station. In 1972 the Shell-Lockheed production system was installed on a well in the Gulf of Mexico at a water depth of 375 feet. A second alternative which takes advantage of readily available semi-submersible drilling platforms and much proven equipment and techniques is the floating platform production system. The first such installation is Sedco-Hamilton's Floating Production Facility (FPF) on the Argyll Field in the North Sea. The system has been operating for approximately three years. A sub sea manifold receives prediction from four satellite sub sea wells where individual production risers transmit the flow up to the platform. After processing in onboard separators, the product is transferred through a ten (10") inch central riser back to the seafloor manifold. A Single Point Mooring (SPM) system and tankers are used to deliver the crude to shore facilities. The production and transfer risers are supported from the platform by riser tensioners which accommodate a maximum rig heave of ten (10') feet. Prudent operation of such a conventionally moored facility requires that the wells be shut-in, and that the risers be purged of oil and retrieved well in advance of weather which would impede such operations. The result is downtime and a less cost-effective program. Also, when production is resumed, flow rates are often lower. The Tension Leg Platform production system offers potential for improved production efficiency because the platform does not heave, roll, or pitch in response to wave motion. The absence of heave not only simplifies the riser design and tensioning, but also permits the risers to remain connected during all weather conditions.

Chapter 3 - Marine Petroleum (Gas) Engineering and Equipment

There are currently 63 fixed steel platforms in the Gulf of Mexico (GoM) in water depths greater than 400 feet. Most of these platforms will have jacket weights in excess of 10,000 short tons. In the context of this paper, the aforementioned parameters define deepwater platforms. Any of these platforms would set a new GoM decommissioning record in terms of size and depth. A number of these platforms have been identified and are being planned for decommissioning within the next few years. Assessing the relevant technology for decommissioning and its resulting cost is a challenge for all concerned. Offshore platform decommissioning is a challenge under any circumstances in terms of planning and executing the work in an environmentally sensitive, safe, and economical way. Among the issues that must be faced are limited availability of equipment and the capability of current technology to adapt to the depths faced in deepwater. This paper presents the potential issues (resources, technologies, and methodologies) that may be encountered in decommissioning deepwater platforms. Fixed conventional platforms in water depths greater than 400 feet are identified and summarized. GoM platform removals case histories are presented to show the various decommissioning options executed to date. The paper concludes in summarizing the regulatory environment that will affect the decommissioning of deepwater platforms. Introduction Table 1 summarizes the GoM fixed steel platforms in water depths greater than 400. Most of these platforms are selfcontained multi-well drilling and production. Early installations are in a six to eight leg configuration. Later designs such as Pompano (VK 989 A) reduced the legs to four, but added multiple skirt piles around each leg. Platforms such as ST 192 A and SP 89 E were designed as a junction between deepwater developments and shallow water pipeline transmission systems. As shown in Figure 1, the deepwater platforms lie near or outside the continental shelf with a greater concentration in Louisiana waters. The orange outlined areas in Figure 1 are the designated artificial reef sites that are managed by either the Texas Parks and Wild Life Department or the Louisiana Department of Wild Life and Fisheries in the western and central planning areas. The decommissioning options available for deepwater platforms are the same as those in shallower shelf platforms. Figure 2 shows the overall production facilities, deck and jacket disposal options. In general all options executed take the production facilities and decks to shore for storage or disposal. The underlying difference is the fate of the jacket. The Complete Removal option takes the conductors and jacket to shore for disposal or storage for future reuse. Remote Reef options assumes that the conductors are removed and disposed onshore and the jacket rigged, lifted, towed and placed at a remote artificial reef site. Topple in-Place is where the jacket and conductors are pulled over into a horizontal position and toppled creating an artificial reef site.

In the current energy shortage and transition context, gas represents an alternative to provide an affordable, reliable and less GHG emissions issuing energy than other available fossil energies. Flow Assurance studies have been launched for a series of gas fields to identify optimal subsea processing functional requirements for a subsea to shore export. The objective is to confirm the robustness of subsea processing architectures identified in previous studies and to evaluate their sensibility towards water depth, step-out, fluid composition and bathymetry. First, real gas fields were selected, the portfolio was completed with notional cases constructed on analogs to reach a good mapping in depth and distance to shore. For each case, bathymetries and PVT models were established. Ledaflow® was used to construct flow models and define the necessary pipeline size based on early and late life flowrates (based upon Erosion Velocity Ratio, Turn down and hydrate risk). When the multiphase export required several pipelines in parallel, an alternative architecture was studied consisting of multiphase pipeline at early life and then gas/liquid separation plus single phases export (separated gas pipeline and liquid pipeline) for late life. Compression and boosting requirement were evaluated. More than one configuration is technically possible. The solution of "multiple multiphase export pipelines" is usually in competition with a "single multiphase pipeline at early life coupled with a subsea separation at late life". The first configuration favors operational flexibility, while the second one favors reduced installation time and cost and allows decreasing the well head back pressure to increase reserves. However, this last solution still requires the installation of a liquid line at late life. Regarding boosting requirements, each configuration has compression needs at late life. The first architecture allows to optimize the compression requirements and increase the process efficiency, while the second one present the drawback of high boosting requirements for the liquid line for great depth and longer step out. For the multiphase export, and a field with very low CGR, the governing parameter for the pressure loss and the compression requirements is the step-out, not the water depth, while, for the subsea separation scheme, the water depth becomes detrimental for the boosting requirements of the liquid line for the great water depths. This large study confirms the feasibility of subsea to shore architectures for gas fields and allows identifying the limitations of the existing technologies and anticipating future technological developments.

A review of the installation phase of Platform Cerveza, East Breaks Block l60-A is presented. It is a chronological presentation based on recorded project logs and on item observations. A comparison between predicted installation times based on historical data and the actual installation times is shown in Figure 1. The review covers some of the planning for special requirements such as weather exposure limits, current considerations, on-bottom stability, and other areas of specific consideration, not normally analyzed for shallower water depth structures. Introduction Beginning in 1976 with the successful installation of the first modern day deep-water platform, the oil industry has focused more and more attention on deep water tracts and methods of producing them. The single piece jacket, by no means a new concept, had never before been used in waters of this depth. The advantages of installing a platform in 935 feet of water in one piece were clear from the start;reduced weather exposure and risk,reduced installation time,eliminated risk in re-connecting jacket sections offshore, andreduced cost since the platform could be installed in a more conventional manner without the need of sophisticated equipment. Once the single piece concept had been decided upon, the task of identifying and solving problems of an unprecedented nature was undertaken. Basic guidelines used in developing the platform's many systems were:keep it simple,limit the risk, andpreserve the economics. Preplanning Approximately eighteen months prior to the launch of project "Cerveza", an installation team composed of engineers and operational personnel was assembled for the pre-planning of the project. This team was responsible for the development, monitoring, and coordinating of the installation planning to insure the compatibility and feasibility of concepts with existing offshore equipment and techniques. Included in the pre-planning was a detailed analysis of the inland waterway which was to be traveled by the tow. This analysis consisted of clearance checks for embankment limits, cross-section channel depths, and turning radii in channel curves. To insure passage, several test tows were conducted with the launch barge ballasted down to the anticipate draft. The data obtained from these tows was used in selecting the precise tow route followed. A major function of the project team was the compiling of a step by step water phase operations manual detailing the procedures to be used for the installation beginning with the load out of the jacket and concluding with the installation of the platform deck. Derrick Barge The derrick barge utilized for the installation was a ship shape hull with an 1100 ton over the stern - 800 ton fully revolving crane and a convention a-point anchoring system. Anchoring studies performed indicated that the existing anchoring system would require modifications to enable the barge to safely operate in 1000' water depths. These anchor modifications were carried out prior to the towing of the jacket. Concurrently with these modifications, special pile handling equipment and pile followers were transported and taken aboard the derrick barge. Jacket Towing A 650' × 170' launch barge was employed in the transportation of the "Cerveza" jacket.

The experience gained with concrete gravity structures is summarized on the basis of the installation of thirteen such structures for oil or gas production in the North Sea. Key data are given regarding the various types of structural foundations. The platform sites are mostly flat or gently sloping with 70 to 153 m water depths. The soils are generally pleistocene dense sands and preconsolidated clays except for recent sands and silts in the upper 0.2–3.0 m. Procedures followed for touchdown, skirt penetration, base seating, and grouting are summarized as are also control measurements needed and data handling procedures. Design predictions are compared with actually recorded field measurements during the installation phase.

Water shutoff treatments need different approach and chemicals in gas and oil fields due to the inverse mobility ratio. Therefore, the primary aim of the research project was to develop special treating solution, which may form barrier phase against the flow of water by in-situ mixing of the treating fluid with formation water. As a novelty, water sensitive petroleum-based solutions were developed, which are stable until they are contacted with water. The induced phase inversion of such metastable systems restricts the water flow by 80-90% in sandstone cores through evolving extremely high viscosity in the mixing zones. Optimizing the composition of the treating fluid containing environmentally friendly chemicals the method was qualified as matured for field pilot tests. In 2013 and 2014, five pilot tests (one repeated one) were carried out at the largest Hungarian stacked oil and gas field. All wells were operating in a depleted gas-capped oil field after terminating the oil production from the lower zone. Special treatment protocol tailored individually to wells was used and injecting 40-100 m3 treating solution, nitrogen drive served to reach deep penetration in the reservoir. Applying short shut-in time, transient production period was observed, and that was followed by gradual and unexpected improvement of production characteristics. Depending on wells, the water production dropped by 40-60% in certain wells; meanwhile in other cases the water production slightly changed though, but the gas production doubled and tripled. The most stunning observation was that all wells never producing oil earlier started to produce substantial amount of oil. Until now, the accompanying oil production is more than 2500 t (18,000 bbl). The outstanding performance of well treatments can be attributed to water shutoff, reduced skin factor, bottomhole clean-up and mobilization of the residual oil saturation from the lower zones. The field project is successful not only in technical, but also in economic point of view. Evaluation of all data proved that the multifunctional stimulation technology might open new vistas in reservoir conformance control in gas fields.

To enhance the working efficiency of a wafer-handling robotic arm and simultaneously alleviate the impact and vibration during the motion process, a trajectory planning approach based on an improved snake optimization (ISO) algorithm is proposed. The following improvements have been made to the snake optimization (SO) algorithm: the introduction of a Chaotic Tent Map for initializing the swarm, the use of randomly perturbed dynamic learning factors to replace fixed values, the application of a cosine annealing learning rate for self-adaptively updating individual positions, and the incorporation of Bayesian optimization for parameterization and fine-tuning of the system's selection process. Furthermore, the ISO algorithm is applied in the Cartesian space of the robotic arm to effectively address the trajectory planning challenge of the single-segment start-stop S-shaped speed curve with arc transitions. The simulation results indicate that the improved S-shaped speed curve has increased by 24.1% compared with the original plan, and the mean and variance rankings of ISO algorithm have, respectively, improved by 60.8% and 63.4%, compared with the SO algorithm. Meanwhile, this study has successfully achieved the Pareto optimal solution with time and impact as the targets based on the established MATLAB experimental simulation platform.

Low-production wells can often be found during the process of gas field production, particularly in low-permeability and tight gas reservoirs. In the Jingbian gas field, some wells (defined as abnormal-low-production wells (ALPWs)) have a much earlier decline period, a larger decline rate, and greater remaining dynamic reserves. In this paper, the low-production gas wells in the Xiagu gas reservoir of Jingbian gas field are taken as the research object, and the existing static and dynamic data of the gas field are comprehensively studied. To enhance the production of the ALPWs, this study focused on the production characteristics, decline causes, and applicable countermeasures of the ALPWs. Static and dynamic data from 57 low-production wells in the Xiagu gas reservoir were analyzed. In addition, differences in production characteristics between traditional low-production wells and the ALPWs are compared using production, pressure and other development indicators. Furthermore, the rapid identification and selection criterion of the ALPWs is established by implementing the producing indexes of the ALPWs. The study shows that several characteristics of the ALPWs can be determined by the production-pressure limiting method. The main determination criteria are listed as follows: The annual production decline rate is more than 20% (far greater than the normal annual decline rate of 5%). The single gas well continues to produce for more than 30 days with a daily production of 10000 m3. The tubing-casing pressure differential is greater than 2.5MPa. The most significant characteristic is that the remaining dynamic reserves of the ALPWs are greater than 250 million m3. All the above characteristics demonstrate that the ALPWs might still have great production potential and the causes for the abnormal-low-production could be analyzed by the node analysis and the IPR curve. Moreover, the bottom-hole water loading and wellbore plugging are the main causes of the abnormal-low-production. This research helps the engineers identify 57 ALPWs in Jingbian gas field, and puts forward adaptive countermeasures for the abnormal production decline causes, which helps the gas field achieve the goal of increasing production and stabilizing productivity. And it could be applied in other similar low-production gas wells with hydraulic fractures in tight gas reservoirs worldwide, and could provide research reference for the progress of enhancing productivity from the low-production gas wells.

This study aims to determine the increase in production capacity through genetic quality improvement using selection techniques with the production capability test method in Tegal ducks. The research was conducted using an experimental method, using a nested pattern experimental design, male as treatment, female as sub-treatment, offspring as replicates, and production characteristics as observations. The selection population of Tegal ducks consisted of 10 males, 50 females, and their offspring. Production characteristics recorded included egg weight, hatching weight, and egg production. Egg production measured was Hen Day Production (HDP) at the initial laying period for 90 days. Assessment of genetic quality using individual breeding values (BV). Each individual's breeding value is calculated, and then the estimated breeding value (EBV) results are arranged based on their rank. Selection of parent candidates is done by maintaining 25, 50, and 75% of the total population. Selection results are obtained by estimating the selection response using different selection intensities. The results showed that the average and standard deviation of the characteristics of egg weight, hatching weight, and percentage of egg production in Tegal ducks were 67.76 ± 4.57 g, 40.40 ± 2.16 g, and 63.33 ± 10.89 %, respectively. Heritability values (h2) and standard error of egg weight characteristics, hatching weight, and percentage of egg production in Tegal ducks were 0.47 ± 0.032, 0.39 ± 0.0589, and 0.512 ± 0.071, respectively. The assessment for selection response was conducted based on three factors - egg weight, hatching weight, and percentage of egg production each week. The proportions were maintained at 25%, 50%, and 75%, respectively. The egg weight proportions were 0.46, 0.29, and 0.15, while the hatching weight proportions were 0.71, 0.45, and 0.23, respectively. The percentage of egg production each week was 47.92%, 30.18%, and 15.85%, respectively. The study’s results revealed that the intensity of selection and selection response of the Tegal duck were higher when smaller proportions were used in the selection process. It should be noted that the production characteristics used in the selection process were different, which resulted in varying heritability values and selection responses. Overall, these findings suggest that careful consideration of the selection factors is necessary to achieve optimal results in the selection process of the Tegal duck

The hurricane metocean conditions presently contained in the 21st edition of API RP2A are in the process of being revised, to account for both the effects of recent major hurricanes as well as changes in understanding regarding the occurrence of severe hurricanes that has taken place since the RP2A conditions were last updated in 1993. This paper contains information on the process used to develop new hurricane metocean conditions, including the hurricane hindcast information used as the basis for the conditions and the statistical methodology used to analyze the data. A summary of the present draft version of the new conditions is also included. The new conditions, when accepted by API, will eventually be published as part of a separate stand-alone API recommended practice on metocean conditions which can then in turn be referenced by other API recommended practices covering offshore structures and operations, such as those addressing shallow-water fixed platforms, jackups, deepwater platforms, and floating MODUs. New draft hurricane metocean conditions are provided for four regions spanning the northern Gulf of Mexico from southern Florida to southern Texas, for all water depths 7.5 m and deeper. The new conditions between 86.5o and 90o W are significantly higher than the conditions currently contained in RP2A, due to the recent severe storms, most notably Opal (1995), Ivan (2004), and Katrina (2005); however, the new conditions in the other three regions are similar to those currently in RP2A. The new conditions are based on the hurricane record from 1950 to the 2005. Unlike common practice in previous hurricane metocean studies, storms before 1950 were excluded from the statistical analysis because the quantity and quality of data available for those storms is considered too uncertain. The division into four regions recognizes the geographical variability of hurricane conditions across the Gulf of Mexico and is an improvement over the uniform conditions described in RP2A. However, a site-specific metocean study is the only way to more thoroughly account for regional variability in developing design and operational metocean criteria for major development projects. Introduction The arrival of major hurricanes Ivan, Katrina, and Rita, three of the most severe storms on record in the Gulf of Mexico, within two hurricane seasons (2004 and 2005), caused massive interruptions in the production of oil and gas in the Gulf of Mexico due to damage to facilities. Given the impact of these storms, and changes that have occurred in the understanding of hurricane conditions in the Gulf of Mexico since 1993 (the year the conditions in API RP2A were last updated), it was decided by the API Hurricane Evaluation and Assessment Team (HEAT) that the hurricane metocean conditions presently contained in the 21st edition of API RP2A (1) should be re-evaluated and, if necessary, revised. An API Task Group, composed of the authors of this paper, was formed to develop new hurricane conditions. It was also decided that the new hurricane conditions would not be included in API RP2A but would be included in a stand-alone API recommended practice document on metocean conditions, which could then in turn be referenced by other API recommended practices.