Covering oil and gas news with the key issues and trends relative to offshore technology, oil exploration, oil and gas E&P operations. POSTMASTER send form to Offshore, P.O. Box , Northbrook, IL To receive this magazine in digital format, go to. Offshore Magazine. August edition. Driller tests solution to stuck pipe problems. Preventative drilling fluid treatment alternative to diesel fuel pills. Jack C.
|Language:||English, Spanish, Japanese|
|Genre:||Children & Youth|
|ePub File Size:||16.38 MB|
|PDF File Size:||17.41 MB|
|Distribution:||Free* [*Sign up for free]|
Offshore Magazine covering key issues and trends relative to offshore oil and gas technology, exploration, drilling, operations and production. Producer of oil. Offshore Magazine covering key issues & trends relative to offshore technology, oil and gas Aug-1, World Survey of FPSOs – Database in PDF Format. First published in , Offshore is recognized as the worldwide leader for covering the key issues, trends and technologies relative to offshore oil and.
Work should begin over the next few months. Articles are available in Beckmans full Middle East review begins on page In the US Gulf Mexico, a number of field development projects will move forward this electronic pdf format year, despite the malaise that continues to hang over the Gulf, writes Bruce Beaubouef, and professional, high- Offshore Managing Editor. Oil Engage visitors on website production is expected to begin in late The second Mad Dog platform will be moored Educate target audience about 6 mi 10 km southwest of the existing Mad Dog platform, which is located in 4, ft 1, m of water.
BoZhong , in the central sector, has been developed by four wells tied into nearby facilities.
The Ml-5 well was drilled 8 km 4. We have evolved for superior performance in ultra-deepwater and optimized our processes, procedures and personnel for unparalleled service. These comprise an operated interest in block The oil is contained in the Mungaroo formation beneath the gas reservoirs of the Brunello field. Brunello and the nearby Julimar are much larger gas accumulations that will provide feedstock for the Wheatstone LNG project.
Heerema has a letter of intent to build the 9,metric ton 10,ton jacket in Vlissingen, the Netherlands, and later to install it. Valemon, between the producing Kvitebjorn and Gullfaks South fields, will export its gas via the Huldra-Heimdal pipeline, while its condensate will be piped to Kvitebjorn for stabilization and onward transport to the refinery at Mongstad. Gro Braekken, managing director, said the industry had committed to a higher level of exploration, which had brought several new discoveries.
But most have been small because the government had not opened sufficient exploration acreage since the mids. According to the Norwegian Petroleum Directorate, frontier acreage drew a strong response, although the total of bidders for blocks was only 37, compared with 46 for the 20th round.
The Ministry of Petroleum and Energy offered 94 blocks and part-blocks — the awards should be issued next spring. A uids heading to Teesside, northern England through the Norpipe system. WorleyParsons will provide detailed engineering for the new platforms and bridges, and functional design and specifications for the subsea facilities.
Subsea 7 has been booked to install two associated pipeline bundle systems, power and communications cables, control umbilicals linking the subsea isolation valves, and tie-ins. ENI has won a license to convert the Deborah field in the southern North Sea to a bcm gas storage facility, which could start operating in Statoil aims to prolong the lifespan of the Njord platform through the Gygrid tieback.
The kit would be stationed in between the reservoirs and the host platform. The operator is Cairn Lanka and the program comprises three firm and two optional wells. There will be two separate hub developments, each based on a floating production unit FPU , subsea drill centers, gas and condensate export pipelines, and an onshore reception facility. Up to 1. The sq km sq mi concession spans waters ranging in depth from , m , ft.
Commitments include seismic acquisition and deep offshore exploration drilling. Offshore Borneo, Eni has found further gas with its latest well on the Jangkrik field in the Muara Bakau permit. It now estimates in-place resources at over 1. The Linshui well was drilled km 81 mi offshore in the Qiongdongnan basin in the South China Sea, in a water depth of 1, m 4, ft. BG plans to drill a second well on its acreage in the area early this year. Lady Nora is one of numerous hydrocarbon pools to the southwest of the Goodwyn A platform.
Water depth is around 80 m ft. Woodside operates the development on behalf of the North West Shelf venture. This covers installation of 90 km 56 mi of in. The derrick lay barge Java Constructor and shallow water lay barge Clough Challenge will handle offshore installations.
It aims to prolong output from existing fields under development, and to prepare the facilities for new roles as regional hubs. This, the company says, will lift reserves recovery from the Kristin and Tyrihans fields by up to MMboe, and will extend life from these fields and others in the area through The new equipment should be installed during summer , entering service the following spring.
Finally, in the North Sea, Bergen Group Rosenberg will build and install a compressor module on the Kvitebjorn platform. Equipment failure is never an option. We ensure optimum, proven solutions delivered every time.
The presentation will showcase the assurance, transparency, accuracy, archiving, and efficiency benefits of the new equipment. With the software, procedures and training, more than a week of time savings per deepwater rig year can be saved.
Further leak detection and pressure analysis opportunities for pipelines also will be addressed. Drillstem testing— operational and safety aspects Shangkar Venugopal Halliburton Well testing costs typically account for approximately one-third of the cost of developing an exploration well.
There are many difficulties inherent to these operations. For this reason, it When it comes to designing a superior workboat, you need functional layouts and durable components built to last. For more than 50 years, BCGP has been building workboats designed to withstand the harsh demands of the working professional. Then we back each boat with superior customer support and factory warranties. This presentation provides insight into the techniques and procedures practiced by Petronas in collaboration with a major service company to provide all the operational and safety steps required for a successful drillstem testing DST operation.
This testing program uses a structured approach that will guide the user through the best practices necessary to effectively plan and implement a DST operation under just about any circumstance. DST operations must be designed to deal with whatever variables that are defined in the safest, most cost-efficient fashion. The method presented in this paper enables the testing design to address properly the following: By following the documented processes disclosed in this paper, testing operations can be developed to avoid catastrophic events that could occur in the safest and most cost efficient manner.
The challenging Kikeh seabed conditions — with the presence of a telecom cable in the middle of one mooring bundle, excessive seabed slopes, and other complicated geology — have forced both parties to find a costeffective and appropriate anchoring solution of the FPSO.
The FPSO mooring was originally designed with three-by-three legs but one of the bundles has to be increased to four legs instead of three to avoid the telecom cable by shorting the anchoring radius and increasing the chain size for that bundle.
At CapRock, the quality of our offshore satellite communications rivals that of many terrestrial communications providers. Thanks to superior quality of service, reliability, customer service and responsiveness, CapRock stands alone in offshore communications.
All to ensure that your employees communicate like they were face to face — even if they are worlds apart. The constructive cooperation between Murphy Oil and MDFT during the site surveys allowed adjustments to the anchoring radius and anchor points to a less risky area during the execution of the geophysical survey and prior to carry out the seabed testing and sampling boreholes. Subsea risers are being secured to the FPSO turret prior to start production.
This is the first application of the suction pile technology offshore Malaysia. New fiber-optic sensors are described. These sensors can obtain both discrete and distributed information regarding key structural integrity properties of the pipeline in addition to operating conditions such as pressure and temperature. Advances in installation methods and procedures means that these sensors can be deployed cost-effectively in new field applicatons as well as retro-fiitted to existing facilities.
Case studies illustrating a number of applications are described. Real-time condition monitoring of subsea pipelines The presentation shows the benefits of wellhead-based subsea processing. It describes in detail how the standardized wellhead interface MARS Multiple Application Re-injection System has been deployed successfully on numerous subsea production optimization projects.
In addition to discussing subsea multiphase pumping and metering applications, the presentation focuses on the recent successful deepwater well stimulation on Chevron Lobito Tomboco project in deepwater Angola.
This project was completed in December This presentation describes several ways in which real-time monitoring technology is emerging as an increasingly significant Case studies on subsea production optimization Ian Donald Cameron MARS Production Systems The presentation will show how application of emerging technologies allows operators to maximize recovery using low-risk, low-cost tooling. Fluid intervention no longer requires full vertical well access for wireline or coiled tubing services.
Chemicals now can be pumped into the well or pipelines in a controlled, safe manner without MODU facilities. There are a number of fluid intervention applications. With a team of over 1, employees operating from 35 global locations, Hydratight has the engineering technology and expertise to offer fast, accurate solutions to your bolting and machining needs. We are the world leader in leak-free connections and pipeline integrity solutions which ensures that our customers improve their operational efficiency.
Using state-of-the-art equipment, our qualified onsite technicians offer extensive monitoring, bolting, machining and training services to maximize safety, reduce plant down-time and extend facility life. To find out more visit www. This is because the unique Arctic environment presents technical challenges which often exceed those experienced with field developments in more temperate marine environments.
The increasing number of offshore Arctic fields currently being safely and economically produced demonstrates that technical solutions are available to develop these valuable hydrocarbon reserves. Expanding international knowledge about Arctic conditions coupled with improvements in material behavior, advances in analytical techniques, wider acceptance of progressive design philosophies, and implementation of reliable Arctic operational strategies enable additional offshore Arctic prospects to be developed.
Several individuals and organizations have provided input for this first survey of offshore Arctic technology challenges and solutions. Environmental conditions and field development requirements vary greatly within the Arctic and Arctic polar view map of ice zones and existing oil and gas lease areas.
Look to Newfoundland and Labrador, Canada. Consider us your landmark location for research and development in cold ocean technologies; unmatched expertise in harsh environment operations; and world-class supply and service for Arctic oil and gas exploration.
Global industry has made us their North Atlantic base of operations for years. Find out why. The edge of the new frontier starts here. It presents a state-of-the-art summary of current geographical sea ice coverage, seasonal ice conditions, estimated hydrocarbon reserves in place, existing Arctic production facilities, field development strategies, concept selection alternatives, export solutions, and future challenges for Arctic and cold regions production.
Jacket structures are suitable for relatively benign first-year sea ice environments such as in Cook Inlet and Bohai Bay. Gravel island structures can be used to resist multi-year sea ice loads in water depths up to approximately 15 m 50 ft in areas such as the Beaufort Sea.
Gravity-based structures GBS can be used in deeper water to resist multi-year ice and to limit iceberg loads. Example GBS applications include exploration structures used in the Beaufort Sea, and production structures offshore the east coast of Canada and Sakhalin Island.
In deeper waters, FPSOs and other floating structure concepts may be preferable with extensive ice management support and may allow emergency disconnect in the event of extreme ice loads. Another major differentiating factor is the availability of an export pipeline network versus the need for a dedicated tanker terminal and icebreaking shuttle tanker fleet. Subsea pipelines have been designed, constructed, and operated in arctic and subarctic regions.
Challenges include burial for protection from seabed ice gouging and the limited time available for summer open water pipeline installation and trenching. Icebreaking shuttle tanker designs and year-round tanker loading terminals show significant advances in recent years.
The world demand for oil and gas will continue to drive Arctic development, which will, in turn, drive development of solutions for some of the unique technical issues and logistical impediments to Arctic hydrocarbon recovery. As technology advances, other Arctic development concepts are becoming feasible. Subsea tiebacks are now in excess of km 62 mi long, offering the possibility of Arctic subsea completions without a permanent host structure. Technical advancements in all-electric subsea control technology, full subsea separation and water re-injection, seafloor chemical storage and injection, and gas re-injection enable the concept of full subsea completions in the Arctic.
Depending on reservoir conditions, some of these development options are currently at a high technology readiness level; some are even field-proven in non-Arctic regions. Research into improved leak detection systems continues to advance industry ability to detect potential leaks and supports the development of new systems for use in the Arctic.
Arctic offshore design, subsea equipment technology, operating strategies, and understanding of Arctic environmental conditions will continue to advance and, as a result, the options available for Arctic and cold regions field development will grow. It is important to note that all aspects must be considered integrally in Arctic development plans. The design philosophy must provide a framework to logically incorporate the elements of Arctic development into one overall life-cycle system design.
This, in turn, will optimize levels of risk and ensure consistent personnel and environmental safety over the lifetime of an Arctic field development. Selected references: Offshore West Africa remains the leading source of information on new technology and operating expertise for this booming deepwater and subsea market and is the most significant offshore Africa deepwater technology event in the world, making Offshore West Africa an event you cannot afford to miss.
Abdel Ghoneim, P. The challenges associated with the design and operation of arctic exploration and production installations are many, and have been discussed exhaustively in the past. The goal here is to assess the current status of these challenges and to review the use of recent ice rules and standards in the design of fixed and floating arctic structures.
The development of new DNV design guidelines on ice structure interaction is also discussed. That work will be completed in or early The project is based on the new ISO standard, and covers both fixed and floating installations.
Finally, a number of past and recently proposed arctic development concepts, as well as some new untested ideas, are reviewed. It is noted that some concepts may not be feasible and may carry heavy risks, while others are quite feasible but may be prohibitively expensive.
Balanced concepts are sought and presented. It is worth noting that in the s it was rare to find ice and arctic specialists, whereas now it is not uncommon to see young engineers pursuing careers in arctic-related fields and completing higher education like M. It is possible to demonstrate that such technology is reliable and effective. The cooperation and commitment of all stakeholders is necessary in order Recently proposed arctic spar concepts.
The focus here is on arctic exploration and production structures. They are given a significance ranking ranging from 1 being most significant with a status in percentage of where the technology is thought to be at present versus the desired situation.
The estimates given are based on the judgment of the author. Further assessment may be necessary to quantitatively make this comparison. Arctic concepts Several concepts for arctic drilling and production systems are being promoted for application in the promising areas for future development. The concepts include drillships for year-round operation, jackups, production spars, gravity-based structures, FPSOs, and floating structures.
A number of arctic spar concepts have been proposed by Sablok and Barras and Murray and Yang The spars are disconnectable upon encounter of ice features that exceed their design limitations and could be constructed of steel or concrete. Bottom-founded fixed platforms, floaters, terminals, pipelines, and subsea options are discussed. In , , and , three proposed arctic concepts and a more recent jackup type design were proposed for Sakhalin II by Gunningham, et al.
A bottom-founded stepped type gravitybased structure in about m ft of water was proposed for the Grand Banks offshore Newfoundland by Fitzpatrick, and Kennedy The second is an earlier spar concept proposed by Murray ; it has a disconnect feature allowing it to be towed away quickly upon threat of an approaching iceberg.
The third is an arctic semi-rigid floater originally designed for Sakhalin Island by CKJ Engineering for 80 to m to 1, ft water depth. Not much detail is given for the arctic jackup concept in Gunningham, et. It is only stated that the concept is under investigation.
A US patent application for an arctic year-round drilling jackup design by Brinkman and Davenport has also been submitted. The gravity-based structures are suited for up to m water depth in regions with multiyear MY ice and to m ft in first year FY ice, respectively.
Jacket and jackup type platforms are feasible to water depth of about 60 m ft in regions like Cook Inlet and the Bering Sea, but may not be suitable for the Beaufort or Chukchi seas. It is possible to construct ice or gravel islands for up to about 12 m 39 ft water depth. Therefore, only Bering Sea-like conditions may be tolerated year-round by floaters that have the capability to disconnect in severe conditions.
Subsea systems are feasible in re- gions with sufficient water depth to avoid ice interaction or with provision of glory holes to house the system with tiebacks of km mi for gas and 65 km 40 mi for oil production. The choice of an appropriate exploration or production system does not only depend on water depth and ice conditions, but also on the ice management and disconnect capabilities commensurate with the arctic region under consideration.
The risks associated with the operation and the consequences of failures have to be quantified and understood.
Additional studies are however recommended to address site specific conditions and logistics. The differences between the two methods depend on the magnitude of the environmental load relative to the permanent load. The allowable stresses are increased by a third when extreme loads are applied. The AISC, 13th Edition Steel Construction Manual has discontinued this practice by only allowing the one-third increase on the portion of the stress caused by the variable and environmental loads.
No increase is allowed for the permanent or dead-load effects. The comparison made here shows that as the environmental loads increase relative to the gravity loads, the LRFD methodology becomes more appropriate with regards to the safety factor.
The a and b notations refer to the operating and extreme load conditions, respectively. WSD methods.
It aims to present a common and documented approach to achieve acceptable safety levels for offshore structure designs in cold climate regions, by adhering to the normative provision of the ISO standard issued in December , and by supplementing it through the provision of practical design recommendations and case studies.
The Guideline should be considered a supplement to the Informative provisions of ISO, providing practical design recommendations, limitations, and case studies Cammaert and Horn, An initial gap analysis highlighted areas where additional research was warranted. One of the areas to be covered in the project guideline is ice effects on floating structures, which has not been addressed in detail in the ISO In particular, the scope of the guideline is to provide practical guidance on key issues related to the following topics: The project is anticipated to be completed by Conclusions When thinking about the present status of arctic technology, thought must be given to whether there is sufficient confidence to support oil and gas exploration and production development in arctic regions.
As always, this is a balance between risks and benefits for all stakeholders. The challenges are numerous and significant, but the associated risks are more manageable now than ever. Even with the considerable uncertainty associated with ice loading and the design criteria, it is possible to mitigate these issues using probabilistic methods and to incorporate a reliable monitoring system and innovative designs that allow ductile structural behavior and fail-safe arrangement.
Depending on the water depth and the ice conditions, many arctic designs have been proven in the past, and that experience is going to be beneficial in designing new structures for deeper waters and more severe ice conditions. The recently issued ISO standard does cover a very wide scope and will be invaluable to the designers and operators of arctic structures. The document still lacks detail for ice load calculations especially for floating systems.
Also, the requirement that ice structure interaction should be performed using probabilistic methods is too general and an alternative deterministic method should be defined.
However, the designers will be relying on class societies for more specific guidance. The definition of local ice pressure dependence on the contact area has been improved in the new ISO standard.
However, due to the sensitivity of the structural weight to the local pressure and hence the feasibility of the design, it is important to optimize the design by employing plastic and nonlinear design methods. The experience from existing arctic shipping, exploration, and production has been successful to date. There is no doubt that existing technology can produce year-round drilling and production systems in all the contemplated arctic regions efficiently, with the same or better reliability than currently experienced in field developments in deepwater and harsh environments.
Brinkmann, C. Cammaert, A. Gautier, D. Ghoneim, G. Gunningham, M. TR, January 31, Murray, J. Sablok, A. The conference Advisory Board once again has put together a program of two days of key presentations by industry leaders.
As in the past, only by participating in this conference will attendees be able to receive its benefits, as proceedings will not be published and no media is allowed in the conference area. Subsea Tieback is presented as a closed forum to encourage free and open discussion for the most benefit of all attendees.
Key Elements Seminar Tuesday, Feb. There is a separate cost to attend this seminar. The daylong event has four sessions plus an update on intelligent well interface standards. Session 1 schedules Bill Donlon, BHP Billiton, to set the scene with a deepwater activity forecast, facts and figures regarding tiebacks, issues and key components, as well as sample layouts.
He will be followed by Tom Kelly, FMC Technologies, who will discuss system considerations, subsea completions, control systems, manifolds and tie-ins, and installation and workovers.
In Session 3, umbilicals, risers, and flowlines will be the topics for Chuck Horn of Technip. He will be followed by Cory Loegering of Mariner Energy to discuss production handling agreements. After that, Don Schlater, SUT, will talk about intelligent well interface standards and is scheduled to end with questions and answers.
The Opening Plenary Session, starting at 8 a. Stephen L. A few session highlights Session 1, Artificial Lift: The presentation will discuss the challenges and learnings of testing a full scale subsea separation and boosting system prior to use on Parque Das Conchas and Perdido.
Jim Hale has 29 years of deepwater experience in the oil and gas industry. Malo Project. Hague has worked for 13 years in the oilfield industry after graduating with a Mechanical Engineering Degree from the University of Houston. It will include an overview of the subsea separation and boosting system at Parque das Conchas BC10 , including assessment of subsea processing performance with field data. To successfully deliver the system equipment, many subsea components required materials that needed to perform on the edge of current technologies.
The 8-year effort to develop and deliver these materials will be reviewed and key points will be discussed to enable this subsea leading materials technology. For more of the latest in information and schedule updates, or to register for the event, go online to http: The combined source and receiver positioning repeatability was achieved to within 30 m 98 ft , second only to permanent installations.
Processing advances made during the project will provide lasting benefits for the static image and achieved best-in-class 4D noise levels. These results show that nodes are suitable for highly repeatable time-lapse seismic programs.
Atlantis began production in October from Miocene turbidite reservoirs 17, ft 5, m below sea level, 7, ft 2, m of which is water.
The desire for repeatable time-lapse seismic in deepwater combined with the challenges of significant surface and subsea installations made Atlantis ideal for ocean bottom node OBN technology. The primary baseline objective was a consistent, high-quality image of the subsalt portion of the reservoir to guide appraisal work. One year after production began, BP put in place a team dedicated to executing the design, acquisition, processing, and interpretation of a time-lapse survey.
Method The project team consisted of a project manager, seismic interpreters, seismic acquisition specialists, safety management personnel, ROV experts, marine advisors, and seismic processors. The team first set about to design the acquisition and to plan the processing flow. Node locations in Atlantis baseline and monitor surveys. However, the producing area of the field only comprised a small portion of the baseline survey image area.
The design sub-team decomposed the original survey into individual single shot migrations and then created stacked images of progressively smaller surveys. Extracting coherency and amplitude maps at the reservoir level on each of these sub-images and comparing section views allowed the team to pare the node count down to an optimal nodes. This reduced the node area from sq km 95 sq mi to 80 sq km 31 sq mi.
The priority for the processing team after receiving the data would be to QC data. This would need to compare the monitor survey to the base line survey on a shot-by-shot and receiver-by-receiver basis to ensure that the exact same traces were repeated and then carried into the time-lapse imaging flow. To reduce processing cycle time, these processes and their resultant QC displays were automated and tested on real datasets.
These flows were modified to account for the deepwater, partial subsalt nature of the Atlantis project, and then tested by processing the baseline survey through the entire flow.
Later, pre-acquisition field trial data was used as a second test data set, which allowed the team to vet the time-lapse components of the processing flow. Operations planning was in parallel to the survey design and processing preparations.
An initial joint risk assessment meeting with the acquisition contractor, Seabird Exploration, set the stage for a joint effort to prepare the field operations. The preparations spanned several months and included redesigning some of the field equipment, creating new procedures, training, and drafting of detailed operation plans.
The result was a smooth field operation in which the plan was executed as expected, the equipment worked as planned, there was no impact on Atlantis production, and most importantly the project was concluded safely. The operation completed within the planned time frame and This node failure rate is on par with results from previous node surveys in the GoM Smit et al.
This success can be attributed to having the right expertise, taking the time to plan, and the willingness of both parties to learn from each other which resulted in needed changes. The geophysical challenge in planning a time-lapse survey is accurate repetition of both source and receiver signatures and positions.
Innovation assured, value delivered. When it comes to high quality service and chemical technology to the oil and gas industry, Clariant Oil Services is right there — on the spot with everything you need. From drilling and exploration to production, transportation and refining, we offer a comprehensive range of chemical technology and services to meet all your current and future needs.
Clariant Oil Services: ClariantOilSvcs What do you need? There is great variety amongst the various node systems. The baseline survey node a Fairfield Z is gravitationally coupled to the seafloor, while the sensor of the monitor survey node a SeaBird CASE Abyss is planted into the soil.
Fortunately, the survey design team could rely on the results of two Atlantis sea trials in Openshaw and Beaudoin, that evaluated both styles of autonomous nodes. These results indicated that, within the range of Atlantis soil conditions and within the required seismic bandwidth, both systems would record seismic data of sufficiently similar quality to support a time-lapse monitor survey. Any minor differences could be accommodated in the time-lapse processing flow.
Achieving node position repeatability in the Atlantis area is challenging, with depths ranging from 1, m 4, ft to 2, m 7, ft in very rugged terrain. This approach was intended primarily to produce rapid position convergence to allow the ROV to move quickly to a target without jitter, but it also appeared to improve overall positioning.
The long tail of the error distribution is caused by a deliberate choice to favor external sensor coupling over closer geometric repeatability. In a few locations, ROV pilots reported difficulty in fully planting the external sensor. The source signature was repeated by designing the monitor survey source array to match the baseline array.
However, the team did elect to tow the monitor source array at a depth of 12 m 39 ft compared to 15 m 49 ft for the baseline survey to gain higher frequency content. This change did not impact repeatability because there were only minor changes to the frequency spectrum within the range of concern.
The advantage of this design is that a new static image of the extra-salt portion of the field could be made with higher frequency content than the baseline survey, which was designed for a lower frequency subsalt image. Any subsequent time-lapse surveys also could take advantage of this. As mentioned, the team also changed the minimum offset requirement, reducing it from 8 km to 6 km. To meet this requirement, careful coordination is required between ROV and source vessel during the operation.
The source vessel must operate at offset greater than 6 km Above Baseline survey — node deployed on the Sigsbee Escarpment. Below Monitor survey — node deployed 3. White arrow indicates external sensor. Conversely the ROV cannot remove a node from the seafloor until the source moves off by that minimum offset. In processing, offsets greater than 6 km were removed from the baseline survey.
To achieve source positioning accuracy during acquisition, the starboard gun array was steered to match the baseline shot positions achieving a high percentage of shots within 10 m 33 ft of the baseline positions. Inclusion of the un-steered port shots gives a maximum source position error of 25 m 82 ft despite considerable loop current activity. The combined source and receiver repeatability is on the order of 30 m 98 ft. This remarkable geometric repeatability, approaching that of permanent arrays, provides a new option for acquiring highly repeatable timelapse surveys in producing fields.
The team began to implement the planned flow and produced an initial image within just seven weeks. However, the initial images exhibited a high degree of time-lapse noise which is observable in the overburden section of the monitor minus base difference section. This noise is caused by variability in the spectrum due to local seabed conditions, subsalt-generated noise, and subtle velocity errors causing non-flat gathers. The team began to reduce this noise through a series of small experiments.
The first experiment revisited the spectrum matching filters. In the initial flow a single, global filter was chosen by analyzing the near offset direct arrivals. An alternative method was tested in which a matching filter was derived for each node and the filter window was lengthened to capture lower frequencies. This proved superior.
Second, the subsalt noise was addressed. A salt transmission attenuating migration was created which attenuated any energy passing through the salt body which encroaches from the north in the overburden.
The producing area image primarily is extra-salt so this had no negative impact on the target image but did remove the subsalt-generated noise. A final experiment enhanced the structural image. Post migration common image gathers were created from the wave equation migration.
A trim statics approach flattened the gathers before stacking. This had a significant impact on amplitude fidelity, image quality, and matching between base and monitor. The result of this new processing flow can be seen by comparing the original monitor minus base difference section to the new difference section.
This project has demonstrated that ROV-deployed nodes can reliably conduct highly repeatable 4D surveys. Source repeatability was achieved to within 25 m 82 ft. Collaboration with the onshore and offshore staff of SeaBird Exploration contributed to the success of this first node-on-node, time-lapse survey. Department of Energy National Energy Technology Laboratory R esearch results over the past decade, including drilling and coring, experimental studies, and numerical simulations, are clarifying the resource potential of gas hydrates.
Key to recent advances is the recognition that gas hydrate is not something exotic, requiring fundamentally new technologies. Instead, gas hydrate is best thought of as the shallow extension of existing deepwater petroleum systems, fully amenable to exploration and potential production using the same tools and concepts as traditional hydrocarbon resources. The conduct of the impending field sampling and production tests will be the next major step in the evaluation of this potential resource.
Methane hydrate, a solid compound formed from the inclusion of methane molecules within an open lattice of water molecules, is familiar to those who work in deepwater oil and gas exploration and production.
The formation of solid gas hydrate plugs within drilling and production tubulars and equipment is a wellknown hazard. However, this article is not about hydrate that forms as a consequence of offshore operations, but instead about issues related to naturally occurring hydrate that forms and evolves gradually over geologic time within the shallow sediments of deepwater continental slopes and shelves.
Gas hydrates require an unusual combination of relatively cold temperatures and relatively high pressures to become stable. In the early s, scientists in Russia noted that methane and water co-exist widely in areas of the Siberian permafrost, and speculated that gas hydrate might be responsible for some unusual reservoir behavior observed in shallow western Siberian gas reservoirs.
The physical occurrence of gas hydrate was confirmed by scientific drilling expeditions in late s and early s that recovered natural gas hydrate samples from the continental shelves of North and Central America. Seaward of this limit, the zone of potential gas hydrate occurrence the gas hydrate stability zone, or GHSZ generally increases with water depth, a trend locally complicated by variations in pore-water salinity, geothermal gradients, and gas geochemistry.
However, even in very deepwater, gas hydrate generally is restricted to the upper 1, m 3, ft or so of sediment. Gas hydrate occurrence also is thought to be most com- mon on the organic-rich continental shelves, slopes, and rises where the supply of biogenic methane is greatest. Potential drilling hazard Since the earliest stages of deepwater drilling, industry practice has been to include inferred gas hydrates deposits along with shallow gas, water flows, and potentially unstable seafloor, as the primary potential shallow hazards to be avoided.
The gas hydrate-related hazard derives from the potential release of gas and water in response to drilling-imparted pressure, salinity, and temperature changes.
Solutions and guidelines outlined for safe and efficient offshore operations in the severe Arctic environment. The webcast will showcase the following Arctic region experts: Shawn Kenny will present an overview of practical engineering solutions that will allow oil and gas operators to safely and efficiently work in Arctic offshore environments.
Kenny will be joined by G. Joe Gagliardi will discuss the challenges of acquiring and processing seismic data in Arctic environments. Listen to and participate in this live webcast by registering at: Contact your sales representative today.
This concern was the primary impetus for a major field program conducted by Shell and partners in in advance of development at the Gumusut-Kakap field offshore Malaysia. Numerical simulations conducted with those data indicated a risk of well-casing integrity loss over planned year production timelines due to weakened physical strength in hydrate-bearing zones. At present, these volumes remain poorly constrained; however, it is likely that the global resource is measured in the hundreds of thousands of Tcfg.
Field data, supported by experimental and numerical simulation studies, confirm that the richest in terms of gas hydrate concentration deposits form in permeable sand-dominated sediments and that such deposits will release gas to wellbores under known production scenarios.
In , a second program conducted by the Chevron-led JIP, in collaboration with DOE and USGS, drilled three sites in which hydrate prospects had been defined using the same concepts and tools, such as integrated geological geophysical facies analysis and inversion of seismic data for saturation estimation, which guide conventional hydrocarbon exploration.
This expedition discovered gas hydrates at high saturations in sands at depths ranging from 1, to 2, ft to m below the sea floor in four of seven wells drilled. These recent positive findings suggest that a realistic global range for potential recoverable resources of gas hydrate from marine sands could well be on the order of 10, Tcf.
Nonetheless, the potential commercial viability of these resources is not clear. In the most favorable case, gas hydrate-bearing sands, production will face technical challenges, and while thought to be possible with proven technologies, they would add significant cost burdens to potential marine development projects.
Extended tests planned Key to enabling gas hydrate production will be a full understanding of the realities of reservoir behavior, the potential production profiles that are obtainable, and the range of environmental implications of field development.
A series of extended duration and closely monitored field tests are needed to advance these issues, and are in planning. Japan has recently announced the intention to conduct a monitored field production test offshore Japan as early as ,16 and the US DOE and USGS are continuing to work with Alaska North Slope operators to begin a field testing and monitoring program as early as Environmental impact monitoring of production tests would include assessment of geomechanical changes in the reservoir and the overlying seals as a result of production.
Reservoir compaction could lead to ground or sea-floor subsidence or instability, whereas loss of seal integrity could enable the release of dissociated gas to the overlying sediments. Work during the JIP field expedition. Mitigating these risks is the fact that gas released from a buried hydrate deposit will be moving deeper into phase stability envelope with potential for hydrate re-formation and self-sealing.
Also the most likely targets for production will be those that are most deeplyburied, as deep burial positively impacts key production issues such as proximity to favorable phase stability boundaries and higher sediment strength. Collett, A. Johnson, C. Knapp, and R.
Kvenvolden, Chem Geol. Birchwood, S. Noeth, E. Hadley, D. Peters, A. Vaughan, D. Bean, Proc. Boswell, T. Collett, En. Moridis, T. Collett, R. Boswell, M. Kurihara, M. Reagan, E. Sloan, C. Collett, B. Anderson, and R. Hunter, eds. Yamamoto and S. Winter, Collett, W. Agena, M. Lee, M. Zyrianova, K. Bird, R. Charpentier, D.
Houseknecht, T. Klett, R. Pollastro, C. Tsujii, T. Fujii, M. Hayashi, R. Kitamura, M. Nakamizu, K. Ohbi, T.