Jackup Operations: New Operational Recommended Practices

This paper describes a study to compare the risks of Floating Production Storage and Offloading Systems (FPSO's), which have never been used in the Gulf of Mexico, with the risks for existing deepwater production systems in the Gulf of Mexico. The major conclusion is that the expected risks for fatalities and oil spills associated with FPSO's are comparable to those for already accepted alternatives for deepwater production. In addition, the oil spill risks are dominated by spills that occur during transportation of oil from the production facility to the shore with either pipelines or shuttle tankers. The major recommendation is to periodically update these results so that they serve as a baseline for future analyses of risk in the Gulf of Mexico. This study was undertaken for the Minerals Management Service to provide information for their use in developing a policy for FPSO's in the Gulf of Mexico. Introduction To date, deepwater (more than 3,000-foot water depth) reserves in the Gulf of Mexico have been developed primarily with the following types of production systems: Spars; Tension Leg Platforms (TLP's); and Subsea Well Systems tied back to these floating systems or to shallow water jackets that may also serve as hubs for other deepwater production systems (Hub/Host Jacket). All three of these types of systems rely on pipelines to transport oil to shore. A potentially attractive alternative to these systems is a tankerbased Floating Production Storage and Offloading (FPSO) system with oil transportation to shore via shuttle tankers. Floating Production Storage and Offloading systems have been used in many areas of the world, but not the Gulf of Mexico. The Minerals Management Service (MMS) funded the Offshore Technology Research Center (a National Science Foundation engineering research center located at Texas A&M University and The University of Texas at Austin), with EQE International, Inc. as a subcontractor, to conduct a Comparative Risk Analysis (CRA). The purpose of this study was to assess and compare the system risks for FPSO's with those for existing deepwater production systems, specifically TLP's, Spars and Hub/Host Jackets. This study was conducted concurrently with an Environmental Impact Statement (EIS) study for FPSO's in the Gulf of Mexico1. Information from both the Comparative Risk Analysis and the EIS will be used by the MMS in developing policies concerning the use of FPSO's in the Gulf of Mexico. The primary objectives of the Comparative Risk Analysis were the following:Assess and compare the system risks for FPSO's with those for existing deepwater production systems, specifically Spars, TLP's, and Hub/Host Jackets; andUnderstand the contributions to system risk by subsystems and phases of operation. Approach The approach used to conduct the Comparative Risk Analysis was developed with the following goals in mind:Provide the MMS with information that can be used for a consistent and objective comparison of the risks associated with the four production systems;Provide the MMS with a level of detail necessary to compare and understand overall system risks for typical production systems

Deepwater oil and gas activities in the U.S. Gulf of Mexico Outer ContinentalShelf (OCS) are regulated by the Minerals Management Service (MMS). The levelof OCS deepwater activities in both the drilling and production arena has showna steady increase, and the discoveries in the deepwater tractshave begun tostack up. Very high rates of production by prolific deepwater wells haveconvinced operators that the deepwater Gulf of Mexico is a sound economicalinvestment, and the trend in this area is expected to increase. Regulatoryconcerns have been viewed by some as a potential barrier to deepwaterdevelopment successes, and in fact, existing OCS operating regulations havelargely been developed on the basis of the expansion of successful bay andinland estuary production activities. These regulations reflect mostly surfaceoperations where daily access to the wellhead(s) is usually possible. Onespecific concern is that the existing regulations do not adequately address thetechnology associated with the new deepwater hardware and operatingprocedures. Discussions with the industry consortium DeepStar and MMS'S active involvementwith the Regulatory Issues Committee have successfully provided an open forumbetween the regulators and operators to identify those regulatory andoperational issues that impact the industry, This paper will address theinteraction and the processes used to study the areas identified by both theregulator and industry personnel as needing attention. Specifically, the paperwill identify the parts of a deepwater operations plan and its use inevaluating the total deepwater production system. The contents of a typicaldeepwater operations plan and how it fits into the operator's project timingand the MMS'S current permitting process will also be summarized. Introduction Deepwater drilling activity is at an all-time high and production fromdeepwater reservoirs is also increasing MMS statistics indicate that the numberof rigs concurrently operating in water depths greater than 1,000 feet hasaveraged 16 during late 1995 and early 1996. In several instances the deepwaterrig count has increased to levels approaching 20 rigs. The continued growth ofthe deepwater Gulf of Mexico, especially the ultra-deep blocks, might beconstrained by the availability of drilling vessels capable of operating inthose water depths. Numerous trade journals have published articles about thesuccesses of GOM deepwater projects, lists of projects under development orwhich are pending, and water depth records for deepwater drilling, mooring, andinstallations. t.s, f We will not attempt to discuss these. The important pointis that the GOM offshore has seen a much needed revitalization with theexcitement of deepwater drilling and production, It is in everyone's bestinterest that the successes continue. Deepwater Regulation There are probably as many answers to the question 'How deep is deepwater?' asthere are responses, From an operations perspective, MMS considers deepwaterwith respect to regulating production activities as beginning where industryuses different technology to develop and produce oil and gas from the OCS.

Hurricanes Ivan, Katrina and Rita passed through over 3,000 platforms in the Gulf of Mexico during 2004 and 2005. While most structures performed adequately, 123 were destroyed and over 183 had major above and or below water damage. There was no life loss and no significant pollution, which is a tribute to the Minerals Management Service (MMS) oversight and American Petroleum Institute (API) design codes, specifically API RP2A (RP2A) for the structural design of fixed offshore platforms. RP2A has evolved considerably over the past 38 years since its first edition in October 1969. Some of this is attributable to changes in engineering practice and the results of experimental studies. Some is attributable to the experiences and lessons learned in large storms and hurricanes. These three recent hurricanes resulted in the largest number of destroyed and damaged platforms in the history of Gulf of Mexico operations. There are several industry, API and MMS studies underway to understand what went right and what went wrong, and to update industry guidelines and practices accordingly. This paper presents the initial results of a study performed for the MMS on the performance of fixed platforms in these hurricanes. The paper also ties-in findings of the work and its correlation to RP2A design practices. Background While hurricanes are not a welcome sight in the Gulf of Mexico, they do provide opportunity to observe how platforms perform in the storms and if required, an opportunity to update design codes accordingly. In fact, development of RP2A was in part driven by several hurricanes in the late to mid 1960's including Carla (1961), Hilda (1964), Betsy (1965) and in particular hurricane Camille (1969), which was one of the largest hurricanes to impact platforms in the Gulf of Mexico. All of these hurricanes damaged or destroyed platforms and the industry responded with the development of RP2A. In the 1970's, RP2A further evolved and the platforms were tested by hurricanes Carmen (1974) and Frederic (1979). The 9th edition of RP2A was issued in November 1977 and contained the first industry accepted wave load "recipe" including the use of 100 year return period conditions and consistent hydrodynamic drag and inertia coefficients. The 9th edition represents a substantial improvement in platform design, and is in fact demonstrated by the better performance of 9th edition and later RP2A designs in these hurricanes, as describe later. In 1985 hurricane Juan spawned in the Gulf of Mexico as a "Sudden Hurricane" and the industry was not able to evacuate all of the platforms. Several manned platforms were severely damaged, including several that toppled during the storm. Fortunately, there was no direct life loss associated with the fixed platform failures. Later investigation determined that the platforms were older vintage and in need of repair prior to Juan. It was clear that specific guidelines were required for assessment of existing offshore platforms for fitness of purpose. The industry, including significant support from the MMS, began a series of joint industry and special projects, as well as API initiatives to develop an assessment standard for existing platforms. The result was RP2A Section 17, developed in the early 1990's and originally published in 1996 as a supplement to the 20th edition. Interestingly, in 1992 during the development of Section 17, hurricane Andrew damaged or destroyed dozens of older Gulf of Mexico platforms. A hurricane the size of Andrew had not occurred since Camille and provided an opportunity to both test and then calibrate Section 17 during its development. In 2002 hurricane Lili damaged and destroyed several older platforms, something that had not been see

In 1993, American Petroleum Institute (API) committees completed the task of writing and issuing two new significant standards: RP 75, "Recommended Practices for Development of a Safety and Environmental ManagementProgram for Outer Continental Shelf (OCS) Operations and Facilities'; and RP 14J, "Recommended Practice for Design and Hazards Analysis for Offshora Production Facilities. " RP 75 identifies the components of a Safety and Environmental Management Program (SEMP) and addresses the identification and management of safety and environmental hazards in design, construction,, startup, operation, inspection, and maintenance of new, existing, ormodified OCS oil and gas drilling and production facilities. RP 14J provides guidance information on process and mechanical design analysis and presents methodologies for hazards analysis of offshore production facilities. The two RPs provide excellent tools for use by owners, operators, and contractors who manage, design, and operate OCS facilities. The Minerals Management Service (MMS) has issued a Letter to Lessees and a Federal Register notice which encourage voluntary implementation of RP 75 by all OCS operators. The MMS will monitor the oil and gas industty's voluntaty implementation and compliance with RP 75 to determine if future regulatory activity is required. References and tables at end of paper. INTRODUCTION During 1993, the American Petroleum Institute published two new Recommended Practices (RP) that establish guidelines and practices designed to enhance the operation of offshore facilities in the Outer Continental Shelf (OCS). The RPs were the result of proactive efforts by two industrycommittees who worked in partnership with the Minerals Management Service (MMS) and the U.S. Coast Guard (USCG) in their development. The two RPs are:RP 75: "Recommended Practices for Development of a Safety and Environmental Management Program for OCS Operations and Facilities"RP 14J: "Recommended Practice for Design and Hazards Analysis of Offshore Production Facilities" The development of RP 75 had as its origin the Safety and Environmental Program (SEMP) concept which was originally proposed by the MMS in July 1991. This concept is intended to address recommendations identified by a study performed by a Marine Board committee of the National Research Council in 1990. The Marine Board's key findings and recommendations included: The current inspection program satisfies the literal requirements of the Outer Continental Shelf LandsAct (OCSLA) for annual and unannounced inspections of each OCS facility. In this sense, it fulfills MMS'S statutory mission. On the other hand, the OCSLA carries a broad mandate to promote safety of life and property and to protect the environment. The Marine Board believes that bythis measure the MMS effort is not totally successful, particularly in the light of greater public expectations regarding safety and environmental protection that have emerged since the OCSLA was amended in 1978. In any event, changes inthe OCS operating environment (including aging platforms, more complex systems and operations, activities in deeper water at greater distances from shore, and changing characteristics of operating companies) have created a need to upgrade the MMS inspection program in order to sustain in the future the generally good.

Synthetic fiber mooring rope is an important emerging technology helping enable the economical exploration and production of petroleum from offshore deepwater reservoirs. Polyester moorings have been used successfully for years in Brazil and were recently approved by the MMS for use by two MODU drilling operations in the Gulf of Mexico. One of the unknown issues associated with the use of synthetic fiber mooring ropes is how to account for damage and the associated lifetime and reliability predictions. The MMS has sponsored research to address the damage tolerance issue including the activity reported in the current paper. This paper describes the results of controlled, damage-tolerance, static tension tests on elements and subrope components taken directly from representative polyester mooring rope products. The results should serve as a foundation for further research into the behavior of ropes with damage including more sophisticated analytical modeling. Introduction Considerable emphasis is being placed worldwide on the economical recovery of petroleum resources from deepwater. The definition of deepwater has expanded in the last decade to now include depths as great as 10,000 feet and deeper. Many different concepts have been proposed for deepwater platforms including FPSO's SPAR's, and TLP's. Each concept depends on the use of a mooring line or tether to keep on station. The taut leg mooring line concept in which multiple light-weight synthetic fibers such as polyester are used as a rope suspended from the platform to the seabed at an angle of approximately 45-degrees from vertical is a very attractive candidate and the concept is growing in popularity. Petrobras has made a major commitment to this concept1 with over 1½ dozen platforms so anchored and there is considerable interest emerging in using the synthetic fiber mooring rope in other parts of the world including the Gulf of Mexico. The American Petroleum Institute has prepared guidelines for the design, manufacture, installation and maintenance of synthetic fiber mooring ropes2. The Minerals Management Service (MMS) recently approved the use of FPSO systems in central and western Gulf of Mexico regions3 and two MODU drilling platform have recently been given approval to use polyester mooring rope in Gulf of Mexico deepwater drilling programs. The MMS is interested in the durability of synthetic fiber mooring ropes and has been proactive in sponsoring research and testing to characterize handling and installation damage4 and to assess the effects of damage. Damage can result from handling the rope during installation, be the consequence of wear experienced during service, or be caused by ingress of sand or marine growth. The integrated program involves testing small-scale rope components (the focus of the current paper), analytical modeling, and a largescale test program. Results from the current study will be used in subsequent validation of an analytical model. The ultimate goal of the program is to develop guidelines for addressing safety and reliability issues associated with damage.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18322, "MODU Performance in Hurricane Ivan," by B.P.M. Sharples, SPE, Offshore Risk & Technology Consulting Inc., and S. Buffington, U.S. Minerals Management Service, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May. Hurricane Ivan tracked through a high-density corridor of mobile offshore drilling units (MODUs) in the U.S. Gulf of Mexico (GOM), resulting in five semisubmersibles losing station and collapse of one jackup. In the aftermath of this hurricane, the industry is reflecting on lessons learned and re-examining industry standards. There was no loss of life and no major pollution from MODUs in Hurricane Ivan. A study commissioned by the U.S. Minerals Management Service (MMS) has chronicled the incidents of Hurricane Ivan to provide information that may lead to more-robust criteria for MODU safety. Introduction A study was commissioned by the MMS to gather information and examine MODU loss of station keeping during Hurricane Ivan. There were approximately 112 jackups and 32 semisubmersibles in the GOM at the time of Hurricane Ivan. Only three jackups were affected, and only one of those was a total loss. Five semisubmersibles were affected. Four left their general location and became adrift, and one moved approximately 3,000 ft. Most of the information came directly from drilling contractors, some came from oil companies, and some came from MMS files. Because the study was not complete at the time the full-length paper was written, the information is preliminary and subject to correction and change. Overview In September 2004, Hurricane Ivan, a Category 4 storm with waves exceeding the 100-year design criteria for offshore facilities, moved through the GOM. Of the more than 4,000 offshore oil and gas facilities and 33,000 miles of pipelines in federal waters, approximately 150 facilities and 10,000 miles of pipelines were in the direct path of Ivan. Damaged facilities included MODUs, offshore platforms, producing wells, topside systems, and pipeline systems that transport oil and gas ashore. MMS received industry reports indicating that seven platforms were destroyed, six platforms and five drilling rigs had major damage, and a substantial amount of oil and gas production remained shut-in because of pipeline damage. Semisubmersible MODUs Ocean Star and Ocean American. Diamond Offshore Drilling reported that drill platform Ocean Star drifted from its moored location. A visual inspection by fixed-wing aircraft confirmed that Ocean Star was afloat with no apparent damage. A visual inspection by aircraft of four other Diamond Offshore rigs operating in the path of Ivan also indicated no apparent dam-age or pollution. The Ocean Star was approximately 1.5 miles east of the storm track. Most of the wires were said to have broken below the rig fairlead near the highest loading point on the system. Hindcast weather data clearly show that conditions exceeded the American Petroleum Inst. (API) 10-year design criteria.

The U.S. Minerals Management Service is responsible for ensuring that offshore oil and gas exploration, development, production, and transportation occur in an environmentally sound manner. This paper outlines some environmental concerns associated with deepwater activities that are being addressed by the Bureau and industry. The policy, strategy and implementation of environmental reviews for prelease and postlease deepwater activity are outlined, along with a description of planned and ongoing research to address information needs. Opportunities for cooperative efforts among the stakeholders in offshore development are increasing and are essential to address important technical needs and regulatory requirements. Introduction Deepwater exploration and development in the Gulf of Mexico hold great promise for the United States in terms of both energy and economic benefits. To realize this potential, industry and regulators must meet the substantial challenge of maintaining environmental quality and protection during offshore operations. The advance into deep water is evidenced by industry's response to recent Gulf of Mexico Outer Continental Shelf lease sales. In March 1997, a lease sale in the central Gulf brought in a record number of bids, over half of which were located in water depths greater than 800 m. Five months later, another record-breaking lease sale in the western Gulf showed similar results, with over 75 percent of all tracts receiving bids in similar water depths. Likewise, exploration and development operations are rapidly moving into deep water, with over 1,300 active leases currently located in more than 1,500 m of water. There are currently over 30 deepwater rigs drilling in the Gulf in water depths greater than 300 m, including two drilling in over 1,500 m. The U.S. Minerals Management service (MMS) is responsible for ensuring that offshore oil and gas exploration, development, production, and transportation occur in an environmentally sound manner. The MMS's number one priority is ensuring that industry's excellent environmental and safety record is maintained as this new frontier is explored and developed. Our approach has been to work cooperatively with industry to gain understanding of this new environment and the technological challenges it poses. We recognize that a serious accident in deep water may undermine the public's confidence in the program, which could delay or jeopardize significant potential benefits. (I) Environmental Concerns/Information Needs The following outlines some of the major issues and information needs associated with deepwater activities. The issues address both localized effects to deep ocean habitats and impacts to coastal environments and economies. Socioeconomic Effects of Deepwater Activity on Ports and Coastal Support Facilities. Social and economic impacts of energy development are often the first felt and most strongly experienced of any impacts. While the Gulf of Mexico has been experiencing social and economic impacts of offshore oil and gas development activities since the mid-1950's, there are some differences in deepwater development that are beginning to be felt. Historically, the effects of offshore activities have been fairly diffused among Gulf coastal communities that serviced the offshore industry in one way or another. However, deepwater activities will have different service requirements, such as larger deeper supply boats.

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.

Shell's Auger Tension Leg Platform (TLP)in Garden Banks Block 426 has been installed in a record water depth of 2864 FSW(873 m). The two 12-inch oil and gas export pipelines from the TLP to shallow water platforms are also the deepest constructed to date in the Gulf of Mexico, requiring record breaking J-Lay construction technology. This paper describes design of the pipelines, including route selection, determination of the wall thickness, buckle arrestor and J-Lay collar design, and connection to the Auger TLP by means of first time use of a steel catenary riser. Construction topics discussed include a description of the deepwater J-lay system and a comparison of shallow water S-Lay and deepwater J-Lay. PIPELINESYSTEN DESCRIPTION The Auger pipelines were designed and constructed to transport oil and gas from Shell's Auger TLP located in the Deepwater Gulf of Mexico Garden Banks Area (GB426) to existing facilities in shallow water (Figure 1). The oil pipeline is a 12.75" (323.9 mm)outside diameter pipeline, 72 miles (116 km) in length, that runs from the TLP to one of Shell's existing platforms in the Eugene Island area (Block EI 331 'An) in a waterdepth of 250 ft (76 m). The gas pipeline is also 12.75" in diameter and runs from the TLP to Hess's existing platform in the Vermilion South Addition area (BlockVR397 'An) in a waterdepth of 397ft (121 m). The oil pipeline is designed for a 50 MBPD flow rate and the gas pipeline is designed to transport up to 150 14MSCoFfDnatural gas. Both pipelines are rated for ANSI 900service, or 2160psig (14.9 MPa)operating pressure. PIPELINE ROUTE SELECTION Several problems exist in routing deepwater pipelines in the Gulf of Mexico:large distance to existing shallow water pipeline infrastructure,generally very rough terrain in the deepwater region (beyond the 800 ft (244m)waterdepth contour),lack of reliable bottom contour and bottom feature data, andpresence of large areas classified by the Minerals Management Service as environmentally sensitive, which means that crossing of these areas by pipelines is prohibited. All these problems were present for the Auger TLP pipelines and route selection, including multiple surveys, required much more time and effort than at anytime in the past, Especially the oil pipeline routing faced the problem of having to circumvent environmentally sensitive areas and its final route is far from a straight line between the TLP and EI 331 "A" platform. Figure 1, which shows the routing of the deepwater portion of the pipelines, illustrates the impact of some of the problems caused by rough terrain. Because a portion of the pipeline (beyond the 1200- 1500foot waterdepth contour) could not be installed with conventional S-Lay, a choice had to be Dade:install a 20-mile-long section of each pipeline by first-time use of J-Lay along a smooth seabed, orlay as long as possible with S-Lay, and have only two 10-mile-longsections of J-Layed pipeline to install.

On April 29, 2009 the U.S Department of the Interior, Minerals Management Service (now renamed Bureau of Offshore Energy Management, Regulation, and Enforcement --BOEMRE) published comprehensive new regulations in the Federal Register applicable to renewable energy and alternate use of facilities on the United States (U.S.) Outer Continental Shelf (OCS). The final rule (Title 30, Code of Federal Regulations (CFR), Parts 250, 285, and 290) defines a new process for offshore renewable energy facilities to apply for and obtain U.S. Government authorization to build and operate offshore renewable energy facilities on the U.S. OCS. These new regulations apply to offshore renewable energy projects such as proposed wind farms, wave farms, or ocean current energy extraction devices located in federal waters of the OCS. The new regulations also describe a complementary role for the Federal Energy Regulatory Commission (FERC) regarding licensing of hydrokinetic energy devices on the OCS. This paper describes how this new regulatory process has evolved and what it means to developers of offshore renewable energy projects on the OCS. This paper will discuss the progress that has been made in defining the regulatory framework and some of the regulatory issues that continue to present challenges in obtaining timely permitting decisions from U.S. federal regulatory authorities. In particular, a number of specific issues related to the potential environmental impact of offshore renewable energy projects will be explored. A well defined, efficient, and predictable regulatory process is critical to successful development of offshore renewable energy projects on the U.S. OCS. Introduction Shifting public sentiment and policy regarding the effects of carbon dioxide emissions from burning fossil fuels on climate change have increased the overall level of public support for low and no-carbon sources of energy production. The nascent offshore renewable energy industry in the United States stands to benefit from these changes. While the positive shift in public sentiment may be helpful to project proponents, creating and refining predictable state and federal regulatory permitting schemes persists as a key ongoing requirement of the emerging offshore renewable energy industry in the United States (U.S.). Several recent developments at the federal level have worked to clarify the applicable regulatory scheme for offshore renewable energy projects. These developments are discussed in the paragraphs that follow. Each of the state and federal project permitting processes includes requirements to assess the potential environmental impact of the proposed prototype or full-scale project. Possible environmental impacts of offshore renewable energy projects have been categorized in several recent studies by the U.S. Department of Interior, Minerals Management Service (MMS) [1] and the U.S. Department of Energy [2]. It should be noted that in 2010, following the Deepwater Horizon oil spill in the Gulf of Mexico, the MMS was reorganized and has been renamed the Bureau of Offshore Energy Management, Regulation, and Enforcement (BOEMRE). This paper will use the acronym MMS to describe those regulatory activities that occurred prior to the reorganization of the agency, and BOEMRE to discuss those activities that occurred subsequent to the reorganization. The federal permitting scheme for offshore renewable energy projects on the U.S. Outer Continental Shelf (OCS) has been evolving over the past few years. Initially, the permitting scheme was the subject of a jurisdictional dispute between the MMS and the Federal Energy Regulatory Commission (FERC). Each agency claimed exclusive permitting authority for selected offshore renewable energy projects. The jurisdictional dispute centered on those projects that used hydrokinetic energy, essentially the movement of water via waves or currents, to produce energy. This jurisdictional dispute was ultimately resolved in April 2009 with an agreement that both agencies would share jurisdiction over hydrokinetic energy project on the OCS and MMS would have exclusive permitting authority over non-hydrokinetic energy projects (e.g. wind and solar energy). The resolution of this federal agency jurisdictional dispute is discussed in greater detail in the next section.

Dynamic Regionalization of the Gulf of Mexico based on normalized radiances (nLw) derived from MODIS-Aqua

Of the potential environmental effects resulting from offshore oil and gas activities, impacts on marine mammals are a concern from an ecological viewpoint and because of unique legal status. Many species of whales, dolphins, and seals have been exploited by man for centuries, some to the brink of extinction (a few to extinction). In U.S. waters, all marine mammals are legally protected from exploitation under the Marine Mammal Protection Act (MMPA), and many of the large whales are also protected under the Endangered Species Act (ESA). Marine mammals and habitats are also part of environmental analyses conducted under the National Environmental Policy Act (NEPA). Historically, “effects” of offshore oil and gas operations on the environment were predominantly associated with water quality and chemical pollutants (oil spills, in particular); other concerns were drilling discharges and other potential chemical releases and platform runoff. In addition to contamination and toxic effects on marine mammals, other potential effects from offshore operations were recognized. For marine mammals, loss of hearing or masked communications can ultimately lead to dire consequences. Noise contamination—the effects of loud and/or disturbing sounds—was a particular concern in Alaska and west coast waters because of special circumstances. They included possible disruption of migratory routes of gray whales and bowhead whales and interference in native whale hunts. Minerals Management Service (MMS) funded several pioneering studies on the effects of noise on marine mammals and, with the Office of Naval Research, supported publication of the landmark book Marine Mammals and Noise in 1995. More recently, a 1995 3-D seismic survey in the Santa Barbara Channel brought Exxon, MMS, the National Marine Fisheries Service (NMFS), several state and local agencies, fishermen, and environmental groups to an impasse over survey procedures and mitigation. Issues were resolved only after several last-minute meetings. MMS's Pacific OCS Region met …

The western and central portions of the northern Gulf of Mexico constitute one of the world’s major oil and gas producing areas and have provided a steady and reliable source of these resources for more than 50 years. The U.S. Minerals Management Service (MMS) is mandated to manage the development of that country’s OCS oil and gas resources, while also ensuring safe operations and protecting the human and natural environment. The level of Gulf of Mexico OCS deepwater activities, both drilling and production, has steadily increased, and the discoveries in the deepwater tracts have begun to stack up. Very high rates of production by prolific deepwater wells have convinced operators that the deepwater Gulf of Mexico is a sound investment, and the trend continues to show signs of increase.

The Gulf of Mexico Gas Hydrate Joint Industry Project (JIP) Leg II conducted logging-while-drilling (LWD) operations in seven wells at three deepwater sites in the Gulf of Mexico during April and May of 2009. The LWD logging program, optimized based on the results of earlier gas hydrate expeditions, featured a research-level dataset that included gamma ray, laterolog and propagation resistivity, resistivity imaging, acoustic velocity, density, neutron porosity, spectroscopy and sigma. The program also provided an opportunity to evaluate new LWD tools that had not previously been available to gas hydrate drilling programs: a quadrupole acoustic tool and an azimuthal propagation resistivity tool. JIP Leg II was successful in determining the occurrence of gas hydrate within sand reservoirs in the Gulf of Mexico, assessing current approaches for interpreting gas hydrate occurrence from geologic and geophysical data, and determining suitable sites for additional drilling and coring in future phases of the JIP program. Basic formation evaluation determined varying gas hydrate saturations in sand reservoirs at each site, and characterized laterally-continuous sections of gas hydrate-filled fractures in clays. The collection of a comprehensive LWD dataset through expected hydrate-bearing reservoirs validated both the site selection process and the logging program, providing new information on the nature of sediments and the occurrence of gas hydrate in the Gulf of Mexico. Lessons from JIP Leg II will help to refine future LWD logging programs in gas hydrate research. Introduction The Gulf of Mexico Gas Hydrate Joint Industry Project (JIP) is a cooperative research program between the U.S. Department of Energy, the U.S. Minerals Management Service, and an industry consortium led by Chevron. Since 2001, the JIP has been committed to achieving a better understanding of the safety hazards involved in drilling through hydrate-bearing sediments. Following a drilling, logging and coring expedition in 2005 (JIP Leg I) that centered on evaluating the fine-grained, clay-dominated sediments that typify the shallow sub-seafloor in the deepwater Gulf of Mexico, the JIP focused a second drilling expedition on the occurrence of gas hydrates in sand-dominated reservoirs in order to assess geohazards as well as investigate gas hydrate resource potential (Boswell et al., 2009). Using a petroleum systems approach, the JIP identified three Leg II sites with the potential for gas hydrate-saturated sand reservoirs (Hutchinson et al., 2008). A logging-only strategy was taken in order to assess the greatest number of sites and test the effectiveness of the program's geological/geophysical site selection approach. The results of JIP Leg II would then be used to plan subsequent JIP field programs that would collect conventional and pressure-core samples from the most promising sites. This report describes the design of the logging program aboard the semi-submersible Helix Q4000, documents the acquisition of data and its initial processing, and discusses preliminary formation evaluation results in the Walker Ridge 313 (WR313), Green Canyon 955 (GC955), and Alaminos Canyon 21 (AC21) lease blocks.

I. Background a. ARCO Experience as a GOM Jack-up User ARCO Oil and Gas Company (ARCO) has operated jack-ups in the Gulf of Mexico (GOM) extensively over the last three decades. During this period, ARCO has drilled several hundred wells accumulating significant experience with a variety of different jack-ups. In 1980, ARCO initiated a structural study to assess the risk of using jack-ups adjacent to fixed platforms. While the study was ongoing, a jack-up rig drilling an exploratory well for ARCO was destroyed during Hurricane Allen, further increasing interest in the subject. In the Spring of 1985, a work group of drilling, geotechnical, and marine engineers was assembled to review GOM jack-up operations and identify areas for improvement. As part of this effort, ARCO funded a compilation of GOM soil strength data, a key factor in jack-up design. The group also worked closely with a rig designer-builder to prepare a preliminary design for a new generation jack-up for GOM operations. The purpose of this paper is to present some of the observations made as a result of this general operating experience and these detailed engineering studies. It is hoped that by promoting more discussion on GOM jack-up designs that the industry (rig designers and builders, drilling contractors, and petroleum operators) will begin design work toward the next generation GOM jack-up. b. Areas for Possible Improvement Two areas were studied in detail: Operating Efficiency and Structural Integrity. Evaluation of operating efficiency reveals relationships between rig designs and final operating costs. For example, drilling records show the cost of certain rig design limitations on drilling operations. Also, by reviewing new technology and benefits from its use, estimates can be made for drilling improvements from advanced rig capabilities. Evaluation of structural integrity reveals the risk associated with failure of the unit during severe environmental loading. In the GOM, hurricanes are the environmental conditions of concern. Challenges exist both in accurately quantifying these storm conditions and consistently applying them to different offshore structures, i.e. MODU-A vs. MODU-B, MODU vs. a fixed platform. c. GOH Focus but Global Concept This paper is focused towards GOM operations since it is a dominant petroleum region warranting specialized rig designs. The concept of an operations-based decision perspective for rig design applies globally however. II. Profile of Present Fleet a. Calendar and Technical Age A survey of GOM jack-ups showed average rig age is 8 years, and only 7 of 185 rigs have been built in the last 3 years. With a useful average jack-up life of 12-15 years, there may be a shortage of good rigs in the near future. More important than calendar age is the "technical age" of the rigs. Although difficult to quantify exactly, the design, contracting, and construction process for jack-ups results in at least 2 to 3 years of lag time between technology and rig completion. For example, an 8 calendar year old rig, will be designed with technology that is 10 or 11 years old. This lag time on technology makes the above age distribution of great concern.