Cooperative efforts needed for deepwater challenges
PANEL IN PRINTCooperative efforts needed for deepwater challenges
Topics of the following presentations include:
Petrobras activity: A review of technical successes in the deep Campos basin of Brazil, company R&D policies and goals. Flow assurance: One of industry's key technical challenges in preventing costly remediation and / or lost production from wax / hydrate plugging in subsea systems. Deepwater pipelaying: Overview of available vessels, equipment, technology, and limitations to laying repairing flowlines and pipelines in ultra-deep waters.  MMS: Actively involved with industry in GOM deep waterMs. Carolita Kallaur, Associate Director for Offshore Minerals Management in the Mineral Management Service (MMS), Washington, D.C., with 30 years of active involvement with the Federal government's Interior Department and MMS, and direct participation in U.S. Gulf of Mexico policy, talks about how her agency is working directly with industry to formulate new policies and regulations to safely and efficiently develop the important new GOM deepwater resources. MMS is the federal agency that manages the Nation's natural gas, oil and other mineral resources on the Outer Continental Shelf (OCS), and collects, accounts for and disburses about $5 billion yearly in revenues from offshore Federal mineral leases and from onshore mineral leases on Federal and Indian lands. Q. Ms. Kallaur, the U.S. Gulf of Mexico deep water, which MMS considers generally beyond 1,000 feet or past the practical depth for fixed platforms, is in the world spotlight as the principal laboratory for developing the technology for safe, economic development. How has MMS reorganized to both regulate and encourage this development? A. To address the many technical and environmental issues related to deepwater exploration, development and production, MMS has initiated a Deepwater Strategy. This is a proactive approach to managing operations, ensuring appropriate environmental and technical review, and focusing studies and research efforts related to deepwater activities. As part of the overall deepwater strategy, MMS is preparing an environmental assessment (EA) on deepwater operations, associated support activities and infrastructure. We are using the EA process as a planning and management tool to ensure appropriate environmental review of future deepwater activities. The objectives of the EA are to identify and evaluate the significance of potential impacts from deepwater operations and activities, to develop appropriate mitigation measures if needed, and identify information gaps. MMS worked closely with industry to develop the Deepwater Operations Plan (DWOP) process to address the technical challenges associated with deepwater developments, particularly subsea production equipment. The DWOP is designed to address industry and MMS concerns by allowing an operator to know, well in advance of significant spending, that their proposed methods of dealing with situations not specifically addressed in the regulations are acceptable to MMS. The plan provides MMS with information specific to deepwater / subsea equipment issues to demonstrate that a project is being developed in an acceptable manner as mandated in the OCS Lands Act, as amended, and the operating regulations, 30 CFR 250. The MMS reviews deepwater development activities from a total system perspective, emphasizing operational safety, environmental protection and conservation of natural resources. The DWOP process is a phased approach that parallels the operator's state of knowledge about how the field will be developed. One important aspect of the DWOP process is an early dialogue about the development strategy, equipment and where approvals are necessary that deviate from existing regulation. Another area in which we have adjusted our resources is operational support and inspections at the district level. With the planned opening in September 1998 of a 5th District Office for the GOM OCS Region, the District boundaries will be realigned to better distribute the increasing workload, a direct result of the increased activity levels in deepwater. An additional area of concern by MMS has been the need to reinforce to all operators — whether deepwater or shallow — about the necessity to operate in a safe manner and not to take shortsighted steps to cut costs or increase production. As part of this safety challenge, MMS has initiated a requirement to hold an annual performance review with each of the 100-plus OCS operators. MMS has also proposed a rule which would allow for the disqualification of operators with poor safety performance. Q. From the Federal government's standpoint, is there recognition of this "new frontier" as a valuable resource development? A. MMS has prepared several publicly available reports that show the value of deepwater exploration and production in the GOM. By year-end 2000, production for GOM deepwater fields is expected to account for up to 64% of the daily oil production and 30% of the daily gas production (percentage of the total GOM OCS production). Projections developed by MMS indicate a substantial increase in all aspects of OCS deepwater activities. Another indicator of the value deepwater activities has is the increased funding MMS has received in the past year for environmental studies, research and administrative initiatives. In Fiscal Year 1998, MMS received an additional $4 million to fund environmental studies. Q. MMS is actively involved in some joint committees and study groups. Can you give some specific examples? A. A key component of our ability to manage activities in the deepwater GOM is participation in a number of committees and study groups. There are many deepwater-related initiatives underway, both internal to MMS and with others outside MMS. Some of these are also international in scope. A practical example of where the MMS and industry collaborated to develop a "reasonable" regulation is the revision of blowout prevention equipment testing frequencies; in this project, a jointly funded study by MMS and several of the industry trade groups ultimately led to changing the "not to exceed interval" for blowout preventer equipment testing to 14 days from 7 days. The cost savings for deepwater drilling activities is substantial, while still maintaining an acceptable level of safety. Several other examples include joint committees with the Offshore Operators Committee (OOC) to address deepwater conservation information submittals, well naming and numbering conventions, and a workgroup involving OOC and the Independent Petroleum Association of America to address production within 500 feet of a lease line. The focus of MMS involvement is group or committee dependent; for example, MMS's role in DeepStar is to investigate regulatory issues that could be hurdles to safe and efficient development of the deepwater resources, and to identify how these can be overcome. MMS involvement in several ongoing research initiatives has often been in an observation or consultation capacity, with input to address concerns and issues from a technical, environmental and regulatory perspective. Perhaps most visible has been the interaction with the Regulatory Issues Committee of DeepStar, which began in 1992. The DeepStar consortium's willingness to involve the MMS has allowed issues and concerns from both sides to be addressed in a timely manner. This has allowed operations to move forward without undue delays (operator's goal) while meeting MMS's safety and environmental protection mandates. Development of the DWOP guideline, and resolution of subsea and subsurface safety device testing requirements are just a few of the other issues that have been addressed cooperatively by MMS and DeepStar. We are also actively participating in several joint industry initiatives directed at overcoming technical barriers to deepwater activities, such as the riserless drilling project led by Conoco, and the FPSO risk and reliability study led by Bechtel. With the concerns that have been raised about deepwater well control, MMS has participated with the International Association of Drilling Contractors and Offshore Operators Committee in an effort to investigate concerns and make recommendations regarding well control guidelines for deepwater drilling. MMS has also been involved with the development of API standards and recommended practices as well as the work of the ISO. MMS has also been successful conducting and cosponsoring workshops to address issues of immediate concern. A recent example was the Shallow Water Flow workshop held in Houston, Texas, during late June 1998. We use these workshops to identify issues and gather information for evaluations and decision making. Other examples include the public workshops to discuss deepwater royalty relief for new (eligible) and existing leases, and the public workshop for discussing unitization and suspensions of production. Shared regulatory responsibilities for OCS activities with the USCG has been another area in which MMS has focused attention, with the preparation of an updated Memorandum of Understanding. The purpose of that initiative has been to avoid duplication of effort and promote consistency in regulating OCS facilities. MMS has also been involved with the U.S. Coast Guard and industry to develop a further understanding of the likelihood and consequences of a vessel colliding with a deepwater facility. In addition, MMS pursues cooperative efforts with industry and scientific institutions on environmental studies. The National Research Council (NRC) has reviewed the MMS Outer Continental Shelf Environmental Studies Program on several occasions and has provided suggestions for the future focus of environmental studies. Industry scientists participate on MMS's Scientific Committee of the OCS Advisory Board, and have been instrumental in the formulation of many large multi-disciplinary studies. MMS is investigating a joint governmental-industry partnership to conduct scientific research to study the fate and effects of synthetic-based drilling fluids and their associated cuttings on marine benthic communities. MMS and industry are also undertaking a joint research effort on the characterization and mitigation of deepwater oil spills. Q. With these deepwater field developments, there has to be a new level of "trust" in industry's ability to install an oilfield facility entirely on the seafloor where it can never be "inspected" in the conventional sense. The option is to impart impossible regulations and potential liabilities that would kill private company development. How do you see this challenge?
A. Deepwater activities do represent a new set of challenges from a regulatory perspective, particularly where there is an inability to directly interact with the production equipment, as in a subsea development. We have worked diligently to understand and keep pace with technological developments, and have engaged industry in dialogue designed to provide information to MMS demonstrating that the deepwater exploration and development systems provide at least an equivalent level of safety and protection. Many of the study groups and joint committees mentioned above have been directly involved with these efforts. Additionally, individual operators, service companies, and equipment manufacturers have participated. Rather than develop some new regulations that would be out of date before they are implemented, in part because of the rapid pace of technology improvements and developments, MMS has chosen to work within the existing regulatory framework in many areas by developing some enhancements and flexibility to allow differences in deepwater projects to be fully addressed. We have been working with the GOM OCS operators to address innovative systems, techniques, and approaches, and the levels of safety provided by such. Both MMS and operators are relying more heavily on risk management for decision making. MMS has demonstrated a willingness to discuss alternatives with the industry, and an improved sharing of information has developed as a result of discussions between agency staff and the operators. A common theme for many deepwater development projects is the operator's desire to fast track the process. In some instances, construction begins in parallel with design work, and time frames are compressed in an effort to reduce the cycle time, i.e., move up the date of first production. MMS is concerned about the emphasis toward fast-track development, particularly in relation to the quality and safety of the systems developed for production on the OCS. Operators need to understand that there are environmental evaluations and regulatory requirements that cannot be compromised as part of the fast-tracking effort. Q. The MMS's published comments on possible use of FPSOs in the U.S. Gulf OCS proposes environmental "guarantees" that are a big hurdle for anyone planning that first installation. Where does MMS and industry stand on this development option? A. The possibility of floating production, storage, and offloading (FPSO) systems in the Gulf of Mexico has been discussed extensively throughout industry for the past two years; MMS has participated in many of these discussions. Industry is actively pursuing FPSO systems as a development strategy for the Gulf, although no one has yet submitted a development application for such. In April 1997, MMS and DeepStar cosponsored a workshop to discuss the state-of-the-industry knowledge regarding FPSO systems and to begin identifying the issues and concerns. An equally important objective for MMS was to identify the sources of information available to help with the environmental evaluations that are mandated by law for OCS activities. Timeliness of the environmental review process for a FPSO-based development project has been a concern raised by many operators. According to some industry representatives, an extended review time could negate the advantages of using an FPSO, specifically the reduction of the cycle time associated with a deepwater development project (time from discovery to first production). MMS has determined that an Environmental Impact Statement (EIS) would likely be required for the first FPSO-based development project on the GOM OCS. The decision to prepare an EIS is based on several considerations, including the potential for environmental impacts, the degree of uncertainty about the significance of potential impacts, and the level of concern or controversy associated with a proposed action. We believe that it would be advantageous to initiate the preparation of an EIS now. There are two options for initiating the EIS: 1) preparation of an EIS in a formally submitted site-specific FPSO-based Development Operations Coordination Document (DOCD), or 2) preparation of a generic EIS by a third-party contractor. In either case, a contractor would be selected through MMS's established procurement process; an operator or industry group would fund the preparation of the EIS and supply the technical information; and the potential impacts of FPSO operation would be analyzed by the contractor. The advantages to a generic EIS are that the process could be initiated sooner; the EIS process could be compressed into a shorter time; and environmental review of subsequent FPSO-based operations could tier from the generic EIS, thus significantly reducing the review time for specific proposals. DeepStar and several operators are currently investigating the option of an industry-funded generic EIS. We continue to gather information and will continue to participate in discussions with industry on FPSO technology. MMS has a better understanding of the FPSO systems, their capabilities, operability and experiences in other areas of the world; and we continue to investigate the international efforts that are focusing on the interfaces between the production and nonproduction processes. There are more improvements in the understanding about issues and concerns that MMS can achieve with the ongoing dialogue with industry, our international counterparts, and the workgroups that have been organized to address FPSO issues. The USCG will have a significant role in any action regarding the use of an FPSO on the GOM. We have initiated a dialogue with the USCG about the process, issues where there may be some overlap in jurisdictions, and what role the USCG would have in any required environmental evaluation documentation. Both industry and government recognize that a serious accident in the Gulf of Mexico would undermine the public's confidence in the integrity of operations. Before any new transportation methods are introduced in the Gulf of Mexico, such as FPSOs, MMS wants to have a high level of assurance that operational standards are sufficient to ensure that the offshore industry's excellent safety and environmental record continues. Q. The precipitous drop in crude oil prices has cut deeply into operators' cash flows. Is there a concern at Federal government levels that this will extend to deepwater development, despite recent incentives like royalty relief? A. We do not think the current drop in oil prices is having a measurable effect on deepwater activity. Our statistics indicate that there has been about a 20% drop in Gulfwide OCS drilling since the beginning of 1998; but there has not been a significant change in deepwater drilling activities, where the rig use continues at near-record levels. Industry has made long-term deepwater drilling contract commitments, and in some cases, commitments to build new-generation ultradeep water drilling rigs, which will ensure sizable exploratory drilling activity levels for several years. A large number of planned deepwater projects under permitting action also continues to be handled by MMS. The one sector of industry that appears to be most affected by the drop in oil prices has been the smaller operators contemplating movement into deep water. Many of the smaller independent companies have been active in recent lease sales, picking up substantial numbers of leases. The long-range impact of low oil prices on these smaller operators is unknown. Most indications are that deepwater operations will continue, and after discussions with many of the operators active in the deepwater GOM, MMS has based some projections on that premise. One of those projections, used in support of the Deepwater EA, is that there will be 5 to 12 new project startups per year in deep water during the next 10 years. With the long lead time associated with many of these deepwater projects, some delays can be expected if oil prices stay low; particularly sensitive are those projects that are marginal in scope and at the early engineering stage of development where there have not been large capital expenditures. The deepwater GOM is not strictly driven by cost; past success, technology developments and better-than-expected reserves and reservoir productivity have been major contributors to commitments to develop deepwater leases. Another factor is the need to replace low reserves inventories. MMS expects that with stable oil prices, continued safe operations, and production results consistent with those achieved to date, deepwater activities will continue to advance. Prices for natural gas have remained stable. Much of the shallower-water activity OCS in the GOM is driven by gas development where the remaining resources and production are approximately two-thirds natural gas and one-third oil. Because of the broad range and scope of activities in both shallow and deepwater, MMS does not expect any near-term effects on its operations. Q. Recently, a lot of media attention has been focused on the socioeconomic impacts deepwater operations are having on the Gulf coastal communities, in particular Port Fourchon in Louisiana. How is MMS responding to these concerns? A. MMS recognizes that some communities are currently taking the brunt of socioeconomic effects related to deepwater activities. Ports that are able to accommodate the deep-draft vessels and fabrication yards that are equipped to handle the enormous deepwater structural components are experiencing greater demands on their infrastructure. As deepwater operations increase in the western portion of the Gulf and as other port facilities expand to capture some of the deepwater business, the demands on specific areas may ease. In April 1997, the MMS Environmental Studies Program held a workshop to identify significant issues related to deepwater operations and activities. Discussions were focused on four disciplines: socioeconomics, environment, physical oceanography, and geohazards. More than 250 participants from academia, state and Federal agencies, and the oil and gas industry attended. The results of the workshop have been used to help focus the development of environmental studies related to deepwater activities. MMS is currently pursuing seven different deepwater-related socioeconomic studies. Q. Where does MMS see the need for technological improvements for deepwater activities? Are there major technical hurdles for deepwater development from MMS's perspective? A. One area of continued concern is intervention capability for deepwater wells. A good summary of industry's current state-of-knowledge and where it is heading was provided in last year's Deepwater Technology supplement to World Oil magazine. It appears that many of the strategies and the equipment necessary for well intervention remain at the conceptual stage of development. MMS believes that the current demands placed on the rig market seriously constrain an operator's ability to perform interventions for subsea wells. This will become an increasing concern as development pushes into water depths that exceed the capabilities of most drilling vessels and the existing fleet of multiservice vessels (only one in the GOM). Another area of concern for the MMS is to ensure that operators live up to their end-of-lease obligations on deepwater leases. On the GOM shelf, operators are able to assign their leases to smaller operators with lower operating costs as the reserve base of the lease decreases. The MMS does not believe this will be the case for much of the deepwater development activities. Operators need to prepare for the high capital expenditures associated with end-of-lease obligations early in the planning stage of the project.
DeepStar updatePaul R. Hays, DeepStar Project Manager, Texaco Inc., Houston, summarizes the status of this important industry deepwater cooperative R&D program. In outlining the organization's makeup and goals, he reviews how the 21-member group has grown and evolved into its present Phase IV. He describes the committee organization and how projects are ranked and approved for further study, noting that Phase IV interest has been heightened by the strong upsurge in deepwater Gulf of Mexico activity. The difference between projects that need to see positive completions and "stretch" goals that are more basic technical involvements is explained. The importance of flow assurance, which takes a high percentage of budgeted funds is covered. And it is noted that long-term factors and global supply / demand needs override present concerns about low crude prices; and that a positive way to cut costs and risks in deepwater development in the present economic environment is to leverage R&D spending by participating in DeepStar. Q. Mr. Hays, DeepStar's background has been detailed in previous publications.1,2,3 Can you summarize its origin, progress and status? A. DeepStar was initiated by Texaco in 1992, as a conceptual study of extended reach subsea tie-backs. It was recognized that a substantial portion of the deepwater (3,000 to 6,000-ft) Gulf could be covered by a finite number of gathering centers that flowed back 40 to 60 miles to shallower water platforms on the shelf. From the beginning, Texaco tried to leverage funds, but potential participants sat on the fence until a definitive program had been organized and a contract had been awarded to kick off the study. The program has grown from the original 11, including the Minerals Management Service (MMS), to 21 companies at present, with a letter of intent for the 22nd. The MMS is no longer officially a member of DeepStar, although we do continue a dialogue with the agency, as it continues to host the regulatory committee meeting which is used as a forum to discuss issues of concern to operators and regulators, including the U.S. Coast Guard. As DeepStar Phase IV continues to evolve, it is a shame that the MMS isn't a full member, as we continue to develop programs in areas traditionally of strong interest to that federal agency, such as a program now being voted on to monitor currents through the Yucatan Strait. The MMS does have responsibility for R&D. But it is my impression that it tends to focus more on environmental issues and selected technical concerns, rather than trying to get a broader grasp of all technology issues related to deepwater development, which could be obtained by participating in DeepStar. Q. How do you handle costs? And how are projects screened and selected? A. We obviously share the costs — 21 to one leveraging is no insignificant accomplishment. The benefit is obvious. It is fairly routine elsewhere in industry for four or five companies to pool $50,000 each to do small joint industry projects. With 21 companies at $50,000 each, we can perform million-dollar projects. We also share the intellectual resources. This is no insignificant accomplishment of the DeepStar forum. We don't have 21 companies with the same level of interest in every project, but we do have a pool of talent to draw from. Each CTR (task) that moves forward must first pass committee screening and then win approval from the majority of the DeepStar Senior Advisory Committee, which consists of one representative from each oil company that is charged with determining program balance. Each committee is responsible for developing a technology matrix which provides a depiction of the map of technology appropriate to the given discipline, as well as providing an assessment of the development status of the different technologies. We use a coarse red, yellow and green notation to describe, respectively, those technologies: 1) in most need of progression, 2) with fewer problems, and 3) perceived as more or less mature. Besides approval of the technical committee and the Senior Advisors, each CTR needs a champion. That is, an individual from an oil company has to step forward to ensure that the project will happen. This champion or subcommittee chair is a guarantor of the program. It is not enough to have a majority vote that something is worth doing. The CTR must be sufficiently aligned to near-term business or technology development needs of at least one company to provide the leadership to ensure that the project will happen and that the results achieved will be of high quality. Q. DeepStar's work is essentially done by committees. It has now moved from Phase III to Phase IV. How has that affected the organization? A. DeepStar, at the beginning of Phase III in January 1996, reduced the number of committees to six: Regulatory, Flow Assurance, Subsea, Vessels Mooring & Risers, Drilling & Completions and the Administrative or Senior Advisory Committee. Shortly thereafter we included a seventh, the Reservoir Engineering Committee. This same structure has carried over into DeepStar Phase IV. We are now deliberating the addition of an Oceanographic committee that appears to put enhancement of a global Gulf of Mexico current model at the top of its list of priorities. The most significant difference between Phase III and Phase IV has been the uptick in strong interest in technology for the deepwater Gulf of Mexico that has led to program growth. The initial program proposed to the 18 Phase III participants was a $9-million program. New participants have expanded that to about $12 million. We are now actively deliberating what additional projects to fund within Phase IV. If the program growth continues, we will either opt for: 1) an extension of Phase IV to 3 years from 2 years, or 2) rolling over a significant portion of additional funds received into DeepStar Phase V. Gulf of Mexico and international operators not in DeepStar are fairly active in requesting information and presentations on the program. I am actively seeking leads to help promote awareness of the program to some obvious DeepStar candidates that, to date, have expressed limited interest. This includes PEMEX and PDVSA, the Mexican and Venezuelan state oil companies, respectively, who have obvious interest in the Gulf of Mexico. Q. Can you summarize what you have termed "stretch goals" for the committees? A. Let me develop that answer a little. As DeepStar has grown, we are taking more active steps to promote a focus of our effort. This project is into its seventh year of existence and surely we have had long-term goals from the beginning. But by its nature, DeepStar is not the type of program with 10-year, long-range goals that seeks to produce nothing in the interim. To the contrary, DeepStar has always had a very short, or near-term focus. Each phase of the program has sought to do its best to evolve technology over an 18-month to 2-year time frame. DeepStar continues to do that, and in all likelihood, will retain that operating philosophy for the foreseeable future. However, we still need to have overriding "stretch" goals, or visions, against which our near-term goals are truthed, to advance us forward in a stepwise fashion; these goals are:
Q. Of Phase IV's technology program budget, flow assurance and related subsea committee efforts have been allocated more than half the total — this obviously reflects a strong industry interest. Can you explain why? A. The $9-million base program consists of $2.1 million allocated for project management and administration, leaving $6.9 million to fund technology. This initial pie was split to allocate $3.435 million (about 50%) to Flow Assurance, and $1.6 million (about 23%) to Subsea. This subsea allocation has a large chunk (about $1.2 million) devoted to electrically heated pipe as a method to mitigate and control the formation of hydrates; this is, in essence, another prong in the attack on flow assurance. These are issues that we face in nearly every operation in which we don't encounter "ideal" crudes. Flow assurance can be an issue in either shallow or deep water, although the problems are obviously increased in deep water with extended reach tie-backs. These problems can be found in West Africa, the North Sea, the Far East, i.e., they are ubiquitous throughout the world. Q. Has the drop in oil prices affected DeepStar? Aside from any belt tightening in R&D spending, is there more emphasis on technologies to cut costs or reduce economic risks? A. We are all aware that oil prices have dropped; at the same time, we may be hopeful that the strong price drop can be explained as an unusual simultaneous occurrence of precipitating factors. These include: the Asian financial crisis, the issue of whether Iraqi crude will again come on the market, the perception that OPEC had increased its quotas, the warm winter in the Eastern U.S., etc. Having recognized these factors, we cannot take reversal of all these precipitating trends as a guarantor of reversal of the price of crude. However, we should remind ourselves of other long-term trends that have shown no sign of abating. The fact that growth in worldwide petroleum energy consumption has been increasing at a rate of about 2 to 3% per year, and despite a crisis in Asia, this long-term trend is forecast to continue. The fact that the U.S. imports more than 50% of its crude oil requirements tells us that increased production from the Gulf of Mexico would be a positive event. The fact is that the vast majority of future reserves are expected to be found offshore, rather than onshore; and further, as explored and developed basins in shallow water reach their peaks and head into decline, the majority of significant future reserves will be sought in deep water. All of these trends forecast a need for technology to enable economic development from deep water. What does this do to DeepStar in the near term, as prices fall and companies may consider retrenchment of their forecast capital budget expenditures? The key to the answer of this question, I believe, is leveraging. If you need to cut back on R&D expenditures, where do you cut first — discretionary in-house R&D spending, or spending that is leveraged at a 21 to one ratio? I believe a longer-term drop in oil prices will lead oil companies to devote more of their attention to maximizing the gains they can achieve by participating in highly leveraged programs such as DeepStar. There is no more economical method of developing technology than by doing it jointly. Q. It's obvious that DeepStar encourages more industry participation? A. I continue to extend an invitation to those companies who have acquired deepwater leases in the Gulf of Mexico or elsewhere, but have not yet joined DeepStar, to initiate the evaluation process; call me for an in-house presentation, and join in an active community of your technical peers to advance and mature the technology required for lower-risk, economic deepwater development. Literature Cited
Meeting Brazil's deepwater reserve challengeAntonio Carlos S. de Agostini, Director — Exploration & Production, Petrobras, Rio de Janeiro, Brazil, discusses the importance of the deep / ultra-deepwater resources to the country. Such resources now comprise 73% of Brazil's total oil / gas equivalent reserves. Review of several key technical accomplishments in the Campos basin offshore development illustrates the results of two PROCAP programs. The technologies of flow assurance and floating production systems are noted as very important to present operations. And a comprehensive summary of emerging technologies that the operator is working on is given, including several new concepts for drilling, subsea production, risers, mooring and vertical anchoring. Q. Mr. de Agostini, does Petrobras have a definition of deep water for purposes of managing offshore operations? For example, when water depth reaches a certain level, does a special technology or operations group take over?
A. In order to better stratify the technological development applied to oil and gas offshore upstream activities, Petrobras has adopted the nomenclature of naming as "deep" waters, those between 400 and 1,000 m (1,312 and 3,280 ft); and as "ultra deep," those beyond the 1,000-m mark. This classification, however, doesn't have any impact, in terms of organizational structure within Petrobras sectors that are responsible for the design, installation and operation of offshore oil and gas upstream activities. The philosophy is to keep the whole "know-how" inside unique groups, independent of the water depths of the fields. Q. Deepwater reserves in Campos are obviously very important to your country. Can you quantify this assessment, and has this been realized by a special commitment by the government? A. The total Brazilian reserve of oil and gas equivalent reached 17 billion boe at the end of 1997. Of this, the oil reserves are distributed as follows: onshore, 13%; in shallow waters, less than 400 m, 14%; and in deep water, between 400 and 1,000 m, 28%. The remaining 45% is in ultra-deep water, i.e., beyond 1,000 m. But, in the latter case, it has been necessary to both develop and extend technology to produce in such water depths. In short, the current Brazilian oil / gas equivalent reserve in deep and ultra-deep water accounts for 73% of the total. The Brazilian government, as Petrobras' main shareholder, is aware of the importance of deepwater reservoirs and has fully supported all the company's initiatives in this endeavor. Q. Under changing laws, do you see any of these expensive, technically challenging areas becoming open to outside participation? If so, won't Petrobras' strong experience keep it in a strong competitive position? A. The Brazilian federal government agency responsible for oil and gas business regulation has already assigned which areas will stay under Petrobras control, and which will be open to international bidding. Several of these latter ones are located at deep and ultra-deepwater sites, as are some of the areas in which Petrobras is negotiating partnerships. Of course, all the deepwater experience that Petrobras developed throughout the past years is a reasonable competitive advantage for new E&P projects. Q. Can you name a few of Petrobras' milestone technical successes in deepwater development? A. To face the deepwater challenges, the company created, in 1986, a capability program called PROCAP-1000 that aimed to generate the technology to enable production in up to 1,000 m. To give continuity to the efforts of the first program, PROCAP-2000 was implemented in 1993. These two programs — together with many other technological agreements established with suppliers and contractors aimed at generating technology — have allowed Petrobras to both develop and implement several technologies in Campos basin, of which we can highlight:
Editor. Petrobras' technical developments through PROCAP and other deepwater developments are detailed by Assayag et. al. in the accompanying article, page 23. Q. U.S. Gulf of Mexico deepwater drillers have faced new challenges in shallow water flows and mitigating paraffin and hydrate buildups in cold, deep water. How many of these problems are common to both Campos and the GOM? How can operators learn more from each other to avoid repeating costly mistakes? A. Fortunately, up to now, Petrobras has not faced shallow water flows during spud-in of wells in Campos. On the other hand, paraffin and hydrates are also a problem for our domestic operations, and mitigating techniques have been developed and implemented. As a corrective method, we have SGN; as preventive methods, foam and multi-size pigs, chemical injectors and thermal isolation of flowlines were adapted. Both of these philosophies and predictive techniques have been extensively discussed with other operators through international forums such as DeepStar, and specific Technological Cooperation Agreements with Shell, BP / Statoil Alliance and, more recently, Agip. Q. You have applied FPSOs successfully in Campos. Are your deepwater projects moving beyond the range of FPSOs? Will you be facing the subsea well and long flowline problem of the U.S. GOM as you move into the ultra-deepwater areas? A. Presently, we consider as technically feasible, the mooring of floaters (being tankers or semisubmersibles) in up to 3,000-m WD; and we strongly believe this limit can be extended in the near future when a real challenge faces us. On the other hand, risers are still a not-completely-solved issue for applications at water depths greater than 2,000 m. Both flexible and rigid (steel catenary riser) solutions are being extensively investigated to extend that limit. When we succeed on this goal, long tiebacks with all the associated flow assurance problems will be, to a large part, bypassed. Q. Can you summarize the toughest technical challenges that remain. What emerging technologies need to be perfected, and who is working on them? A. A series of challenges and constraints have to be faced and overcome to produce the deep and ultra-deepwater fields offshore Brazil. Petrobras has already identified the following technological demands that are crucial to be addresses; they are:
Advances in deepwater drilling technologies, like multilateral wells located in 2,000 or 3,000-m water depth, are today not only a vision, but a reality that brings good alternatives to homogeneously drain the reservoir from a Stationary Production Unit. On the other hand, extended reach wells (ERWs) can have the same success in deep waters as they have in shallow-water fixed platforms or in onshore operations. Indeed, ERW drilled in deep waters, besides making it possible to reach far targets in the reservoir, also reduce the probability of hydrates and wax formation due to the higher flow temperature, when comparing flowing inside the well to flowing in pipes at the seabed. Another important alternative for drilling and completion in deep water is the slender well concept that can be used both in subsea and in dry completion alternatives. New subsea horizontal trees for 2,500 m; lighter and smaller manifolds with innovative concepts increasing reliability and availability of the system; reliable connection systems; and composite-material risers are required for the new environment. In deepwater conditions, many operational problems and huge production losses may occur due to organic deposition and hydrate formation in flowlines in which low temperatures, both at the seafloor and in the reservoirs, are predominant. Alternatives for the mitigation of hydrate and wax deposition in subsea pipelines will remain of fundamental importance as we move to ultra-deep water. The development and improvement of mooring systems, aiming to reach deeper water and reduce cost of materials / installation, should focus on use of a new kind of anchor with the capability to withstand vertical loads, piles driven by suction, synthetic cables, mainly polyester, and the application of new configurations such as the taut-leg-type mooring system and the Differentiated Compliance and Anchoring System (DICAS). Q. What else is critical? A. Risers, flowlines, and multifunctional umbilical cables are undoubtedly some of the most critical equipment components of the floating production systems in ultra-deep water. A large-diameter piggable export line system is a big concern. Our vision is that the flexible flowlines have to be redesigned for ultra-deep water; in addition, light structures and new riser configurations have to be used to reduce vertical loads. A major technological breakthrough in these areas should be reached by the industry, in contrast to the current development that has been achieved by searching mainly for incremental increases in the operating depth. The use of rigid flowlines and steel catenary risers (SCR) is another option for the transportation of oil and gas in ultra-deep waters. Presently, the SCR is operating in tension leg platforms (TLPs) in the GOM; and another installation has been scheduled to take place this year in a semisubmersible-based floating production unit in Campos. The installation of rigid and flexible lines in ultra-deep water needs the use of very complex laying vessels. Since all of these issues are of fundamental importance to deepwater operators, the whole oil industry is working very hard on them. Q. Has the unplanned-for emergence of low-oil-price economics altered Petrobras' R&D philosophies? A. The present oversupply of oil in the international market, with the consequent fall of the price, brings a new, big challenge to operators. It is mandatory not only to make technically feasible the exploitation of oil fields beyond ever-demanding limits in terms of water depths, but to produce them in a cost-effective way as well. Petrobras has been working hard to match both technical and economical demands. This is a permanent compromise with our shareholders.
Flow assurance: Industry advances in wax / hydrate controlIvor Forsdyke, a Production Chemist with BP Exploration Operating Co., Middlesex, England, updates his previous introduction to the flow assurance problem (Deepwater Technology, August 1997, pp. 22–25) with a discussion of what operators are learning, and where, geographically. The increased involvement of service companies, with more alliances and joint industry projects, is noted as an important development. The work of DeepStar's Flow Assurance Committee is overviewed; and several other industry projects covering a wide variety of related topics are discussed. The key issue throughout the following presentation is the development of positive methods of preventing the formation of wax / hydrate (and asphaltene / scale) buildups in long, cold flowlines and risers, in which retaining the heat of produced fluids by insulation or other means, and mechanical remediation / intervention is impractical. Q. Mr. Forsdyke, in a previous presentation, as noted above, you gave a comprehensive definition of flow assurance and the need for operators to incorporate preventive systems into deepwater project designs and installations. Have recently installed projects and new development options highlighted or added to these basic concepts?
A. The basic concept of flow assurance is still the need to control fluid behavior so as to prevent costly remediation procedures and lost oil associated with solids deposition. The current trends in exploration are moving into deeper and deeper water, such as the Atlantic Frontier (AFP), West Africa and the Gulf of Mexico (GOM). In these environments, produced fluids may have to be transported over increasingly longer distances, including long risers in hostile conditions, to either existing shallower water facilities or FPSOs. In either case, the produced fluids will inevitably cool to the cold sea temperatures, bringing into play the issues of wax and hydrate formation. The accompanying figure illustrates the challenging subsea environments occurring in typical development depths in four geographical areas. Traditional methods of avoiding wax and hydrates through heat retention backed-up with intervention are becoming technically difficult and prohibitively expensive for flowline lengths of greater than 10 miles. This is true even in the relatively shallower waters of the North Sea. Our focus, therefore, remains on preventive measures to facilitate cold-fluid transport in long, deepwater flowlines, thus eliminating the distance limit of the current systems. Q. You have noted a variety of existing and proposed preventive methods under the general categories of thermal, mechanical intervention and chemical inhibition / prevention. Are any of these seeing increased emphasis as industry's knowledge is broadened? A. Although significant progress is being made, the technologies required to allow a single uninsulated flowline of significant length are not yet advanced enough, nor available, to impact project design. As a result, we are seeing the installation of short- to medium-length insulated flowlines, often looped, to allow access for round-trip pigging or TFL. Current projects in the AFP, West Africa and GOM are still heavily reliant on expensive insulation options to avoid the wax and hydrate envelopes. Chemical inhibitors (including methanol and glycol) and intervention, although included in these designs, are still seen as back-up for transient conditions such as shut-ins or turndown due to high cost, uncertainty in performance and, more recently, environmental concerns. However, experience is starting to show that our confidence in thermal modeling of flowlines may be not as good as we would wish. Assumptions about insulation performance, thermal properties of the seabed, temperatures and currents have been in error, leading to steady state flowing temperatures closer to, or inside, the solids-formation envelopes. As a result, chemical inhibitors and / or intervention are becoming an increasingly important strategy, especially as the step-out distances and water depths increase. In fact, it may be our inability to sufficiently thermally insulate the long risers which will govern the flow assurance strategy. Therefore, new projects are attempting to establish the OPEX associated with chemical use and intervention (including any deferred production) into the life of field design. However, significant improvements in our capacity to assess inhibitor requirements and performance prior to production are required. Hence, at present, new projects are incorporating a combination of these strategies in an attempt to minimize capital and operational cost while minimizing operational risk. Q. You have emphasized how important the application of preventive chemical methods can be in avoiding costly interventions to remove blockages and / or substantially reduce capital expenditure. Can you elaborate? A. There are many examples of blocked pipes around the world, but there are far more examples of successful prevention or management of hydrate / wax issues. Where prevention / management has been designed into a development, we rarely experience problems. However, as the up-front capital costs associated with strategies such as insulation and / or intervention escalate, emphasis is changing to managing these issues through operating costs, such as the deployment of chemicals. At present, the right solution is a combination of up-front design and chemical inhibition; and this is still project specific. For example, to control wax deposition rates in a number of subsea flowlines from an FPSO, it was decided to use insulation to minimize wax build-up rate, combined with hot-oil flushing and pigs. A wax inhibitor was selected as a back-up if the intervention frequency turned out to be higher than anticipated. Based on lab performance data, it transpired that the inhibitor was more cost-effective than the additional insulation requirements during specific production periods, including turndowns. In any subsea development, creating a wax and hydrates control strategy is still a combination of cost and risk management. We tend to regard our mechanical / thermal methods designed into the project as low-risk, with well-defined costs and performance. However, recent experiences with high-performance insulation systems, such as complex bundles, suggests that this may not always be the case. We cannot always guarantee quoted insulation performance or production rates for any number of reasons. Thermal profiles may be very different from those predicted, resulting in the flowlines operating within or close to the solids formation envelopes. Any margin of safety from unplanned shutdown may be lost. As a result, the additional operating expense of deploying chemicals also has to be borne, on top of an ineffective insulation system. It is estimated that up to 10% of deepwater development costs (primarily high-performance insulation systems) could be saved if effective chemical solutions such as low-dosage hydrate and wax inhibitors could be made available. As our confidence in inhibitor selection / performance improves, we are shifting toward the chemical solution. In another example, a number of subsea black oil and condensate fields are tied back to a central processing facility. One particular multiphase black oil line will potentially operate within the hydrate region under certain conditions, including shut-in and start-up. The development of low-dosage hydrate inhibitors has enabled this project to save a significant percentage of the development cost through eliminating the huge regeneration plant required to handle the large volumes of methanol that would have traditionally been required. Q. It would appear that some chemical supplier / service companies are intensifying their R&D efforts in the areas of hydrate and wax treating. What are their goals, do they see a growing market and has any progress been announced yet? A. Traditionally, the areas of hydrates and wax management have been handled exclusively by the operators. These issues had to be addressed correctly at the design stage and a certain amount of contingency included into the design. The tools for assessing the likelihood and severity of such problems, together with inhibitor requirements, including chemical selection, were in-house and often proprietary. The service companies were seen as just chemical suppliers. However, this relationship between service company and operator has changed over the last few years, and is still evolving. With the emergence of alliances, the service companies are becoming an integral part of the production operations team, typically responsible for daily management of a field's production chemistry issues. In this role, they have been charged with solving and preventing production process upsets. To meet these requirements, they are needing to improve their understanding of production processes and fluid / solids behavior. As a result, they are investing in programs to model production fluids, improve confidence in preproduction screening and develop performance monitoring. To meet the challenges of deep water, new chemical developments are also required, as the emphasis on hydrate / wax management changes from up-front design to operations. Traditional chemicals are neither cost effective, nor (on their own) technically suitable for deepwater duty. New options are needed both from the operators, to make the developments economic, and from the service companies, to offer solutions for the growing deepwater environment. As a result, we have seen cooperation to develop new products between service companies, operators, chemical manufacturers and universities. The emergence of a number of low-dosage hydrate inhibitors is the result of such cooperations. Here, the operating companies have often been the initiators and driving force behind initial development of new technologies (driven exclusively by technical and economic need), with the service companies providing the expertise in formulating them into product lines and providing the service to deploy them. Wax inhibitor development is also beginning to see a similar trend. Q. What is DeepStar doing with flow assurance? It would appear that several subcommittees are active? A. DeepStar is still focused primarily on hydrate and paraffin wax control. Past work has concentrated on assessing the industry state-of-the-art in hydrate and paraffin prediction for deep water and providing effective remediation. A number of technologies, including extended-reach coiled tubing to remove blockages, guidelines and handbooks are under development. Members have also benefited from sharing experiences; and the Flow Assurance Committee continues to provide an arena for both operators and service companies to examine deepwater operational issues and explore new options. Presently, the program is focused on obtaining much-needed field data on hydrate / wax formation, and field evaluation of preventive and remediation technologies. Two committees (hydrates and wax) are active in developing test programs and designing field trials. The hydrate group is examining the performance of inhibitors in black-oil and condensate systems. The group is planning field trials at near-GOM conditions. The wax group is concentrating on collecting data on deposition rates and profile in a subsea flowline. It is also examining inhibition technologies with an option to test in this subsea line. Supporting these two groups is a third committee working on providing new instrumentation essential to the success of the field trials. The Flow Assurance Committee will continue to pursue improvements in understanding fluid behavior, better prediction models and qualifications of control strategies. For example, the data generated will eventually supplement other programs such as the University of Tulsa's paraffin deposition JIP. DeepStar itself will initiate studies into other flow assurance issues such as asphaltene deposition. It will examine new inhibitor technologies and continue to develop guidelines for operators and design engineers. Q. What other important industry flow assurance projects are active or planned? Are these joint projects or alliances between operator and suppliers? A. There are a number (too many to include all) of projects, at present encompassing a wide range of flow assurance topics. Apart from DeepStar, most of these are focused on a very specific problem such as prediction of paraffin wax, or development of an inhibitor. In the majority of these projects, the partners involved tend to be operators; but more recently, we are seeing involvement of the support sector from systems-design houses to chemical and well service companies. As explained above, the development of new hydrate inhibitors has been initiated by the operators, driven by the technical need to make deep water economical. Programs developing hydrate inhibitors include those led by BP, Shell, Colorado School of Mines and Institut Francais Du Petrole (IFP). This strategy has also been extended to the development of new wax and asphaltene inhibitors through programs such as Waxattack and DART; these programs are both operator-led and operator-dominated JIPs. The goal of both programs is to develop inhibitor packages to prevent wax and asphaltene deposition blocking subsea production facilities. The chemical service companies are showing an active interest in all these projects, as future business will depend on their success. In other programs, emphasis has been on investigating fluid behavior and developing or improving deposition models. The University of Tulsa's paraffin deposition JIP is such an example. Here a consortium of 34 partners (24 operators), managed by the University, has built two large flowloops to measure the wax deposition phenomenon in both single and multiphase flow regimes. This data will be used to develop a true multiphase wax deposition simulator. It was unlikely that any of the partners would have attempted this task alone. IFP is in the process of launching a program to examine the restart of gelled oil pipelines, where — following a shut-down — the fluids cool to below the pour point. Several operators have found, to their cost, that this age-old problem can still occur regularly. Hydrate research continues at CSM and SWRI; and GPRI also has a number of flow assurance projects under its wing. In addition to investigating fluid properties and developing chemicals, projects also exist to improve and develop new hardware technologies. Petrobras has been working on improving operational pigging for subsea use. New insulation materials for deepwater duty are under development. These hardware options are still of significance, especially if they can make substantial cost reductions. Q. What direction do you see flow assurance taking in the next few years? A. The key issue for deep water is keeping flowlines / wells clear of solids. The main issue has been wax and hydrates. Most attention has been focused on retaining heat; but with longer risers and flowlines, this will be impractical. Rather, we must accept "cold oil" transportation and deal with the wax and hydrates. This will require development of reliable, totally effective chemicals and / or regular intervention. Either way, we will have to find novel methods of deployment. In the case of inhibitors, we must consider alternatives to pumping chemical great distances through small umbilicals. We must be innovative with intervention, finding new ways of deploying pigs. We must also consider other flow assurance issues such as asphaltenes and scales. While not currently a major issue, they will, increasingly, cause us problems. Here the big issue will be deployment of chemical or mechanical intervention in remote wells which may be horizontal or multilateral. The technology for treating such systems is very immature, and yet we will be very reliant on them. Future flow assurance will not just be about developing new chemicals, but how to deploy them in the deepwater environment.
Deepwater pipelaying: Industry can handle proposed installationsEdward P. Heerema, President, Allseas Group S.A., headquartered in Switzerland, says his contracting side of the deepwater industry has no equipment shortages due to the limited number of projects actually underway. And projects successfully completed in more than one mile of water depth in the Gulf of Mexico prove an existing capability. Limitations he does address are related to individual project pipeline designs, which may challenge material supply and manufacturing capability, e.g., required wall thickness for large diameter pipe in very deep water vs. mill capability to produce it. The distinction between "trunklines" and "flowlines" is discussed. And comments on industry's ability to repair ultra-deepwater lines are added. Q. Mr. Heerema, the deep ocean waters of the world are the "new frontier" in oil and gas development. Is the pipeline industry sector ready yet to handle the needs of projects underway? A. Certainly. Rigid steel pipelines have already been laid by our own company using the Lorelay, Fig. 1, in water depths of up to 5,400 ft in the Gulf of Mexico. It is feasible to lay pipe in considerably deeper water, as long as the pipes can be manufactured. Steel catenary risers have also been installed in very deep water. There are vessels that lay pipelines in virtually any water depth in S-lay, such as Lorelay and Solitaire, Fig. 2. as well as other vessels that can lay in J-lay mode. Q. What are the basic causes of any limitations today, for example: equipment shortages, logistic delays, etc.? A. There are no equipment shortages; in general there is an equipment surplus as there aren't that many deepwater projects every year. The limitations are not so much dictated by equipment capabilities, but more by the limitations imposed by pipeline design, material aspects and manufacturing capabilities. A number of studies have been made for ultra-deepwater projects. These indicate that the most extreme deepwater pipe that can be installed is, at present, about 26-in. OD, with 1-5/8-in. (41-mm) wall thickness. This limitation is determined by the minimum D/t (diameter / wall thickness) ratio that pipe mills can, at present, achieve on rolled pipe, and the thickest wall that can be rolled. Due to the hydrostatic collapse criterion on the seabed, the greatest water depth in which this pipe can be laid is about 11,500 ft (3,500 m). A 32-in. pipe is limited to about 9,000 ft (2,700 m) water depth. Small-diameter extruded pipe, conversely, can be laid in water depths greater than 11,500 ft. Several operators have leases in the Gulf of Mexico in more than 6,000-ft water, the deepest being more than 8,500 ft. Q. As far as pipeline construction is concerned, does it matter whether the system is called a trunkline or a flowline? A. Actually, a distinction can be made into trunklines, export lines and flowlines. A trunkline is a major line that brings large volumes of product gathered from one or more oil or gas fields to shore or to another pickup point. Trunklines are generally 20 to 42-in. OD and can be hundreds of miles long. Gas lines generally have larger diameters than oil lines. Export lines bring gas or oil mostly from a single field to a central processing unit or platform. The diameter range is often between 10 and 20 -in. OD. In the Gulf of Mexico, such lines are typically installed from deepwater manifolds or TLPs to existing shallow water platforms. Flowlines are generally short, small-diameter lines that bring product from the wellhead to a manifold or processing platform. Flowlines generally vary from 6 to 12 in. in diameter, and are usually only a few miles long. Present field developments often have flowlines and export lines operating under high temperatures and pressures relative to the seabed environment. In most cases, trenching of these lines is required for protection or insulation. Sometimes these high temperature lines need insulation by means of a pipe-in-pipe system, in which the pipe is encased in another pipe and the annulus filled with insulating material. From an installation point of view, the requirements are often much the same, Lorelay and Solitaire, for example, are able to lay flowlines, export and trunklines on a project in a single mobilization. Q. The connection of deepwater pipelines, flowlines, umbilicals and other "bundles" to subsea manifolds, templates and riser bases using ROVs and other remote control facilities is becoming extremely complicated. Are present systems working or are new technologies needed? A. Yes, present systems generally work well, and this is the result of the enormous effort made by the industry in recent years. Great advances have been made in remote technology. There is now ample experience with "stab and hinge-over" startups of pipelines, "Inverted U" spoolpiece installations, pipeline end manifold (PLEM) installations, steel catenary riser installations, and so on. Q. Where are we in our ability to repair ultra-deepwater pipelines? What is industry doing to meet the challenges? A. The feasibility of having pipelines in deep water relies on the ability to repair them diverless in case of damage. A repair of a pipeline was done by Allseas in 5,400-ft water in 1997, which demonstrates this to be entirely feasible. In that particular case, a damaged pipeline section was removed after a remotely performed underwater cut was made. The end of the line was subsequently retrieved by a remotely inserted gripping clamp, and after dewatering through pigging, the pipeline was pulled back into the firing line of the Lorelay and was re-laid from that point onwards. Alternatively, a mid-line repair can be performed by cutting out the damaged section and retrieving, in sequence, both ends of the line. After welding on a flange or other connector, each end can be lowered again, the exact lay-down position measured, and a spool fitted between the two ends. A remote tool would connect the flanges of the pipeline and the spool. Such tools — hydraulically operated — exist, as do corresponding connectors.
Copyright © 1999 World
Oil |
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ive presentations
offered in response to questions posed by World Oil carry the common theme:
technical and operational challenges to safe and economic development of the oil / gas
resources in deep- and ultra-deep waters in the U.S. Gulf of Mexico, offshore Brazil and
West Africa, the North Sea / Atlantic Frontier and, potentially, other international areas,
are too daunting for any single operator. Information on lessons learned must be shared. And
because the operations are evolving into ever-more-sensitive environmental issues, the
collective industry cannot afford the repercussions of a serious incident by any of the
growing number of existing / new operators. 
Paul
R. Hays, DeepStar Project Manager, Texaco Inc.,
Houston, received the PhD degree from the University of Illinois at Urbana in 1980. He
worked for a year on flutter analysis for the aerospace industry before joining the oil
industry in 1981. His early involvement with deep water was with field development
technology for 1,000-ft water offshore Norway, with initial technical focus on deepwater
production / drilling. He has been involved with acquisition / development of technology
to enable development with floating production systems; and these efforts evolved to Gulf
of Mexico focus with water depths to 2,200 ft. He began work with DeepStar focusing on
pipelines. As the program expanded in Phase II, he took on greater responsibility for
production risers. And in Phase IIa, he assumed additional responsibility for the Drilling
/ Completion committee. Mr. Hays became leader of the overall DeepStar program at the
kickoff of Phase III in February 1996.
Antonio
Carlos Sobreira de Agostini, Director — E&P,
Petrobras, Rio de Janeiro, Brazil, graduated from the mechanical engineering school at the
University of São Paulo (São Carlos School of Engineering) in 1966. He
joined Petrobras in 1967, starting his career as a project engineer in refining /
petrochemical; from 1975 to 1980, he was responsible for construction of a 180,000-bpd
refinery in the State of São Paulo. From 1981 to 1986, he was in charge of platform
construction for the Campos basin complex. In 1987, he was appointed director of Petrobras
International S/A — Braspetro, a subsidiary; one year later he was named executive
VP. From 1990 to 1992, he served as advisor to the president of Petrobras Fertilizantes,
another subsidiary. He later returned to the engineering department, and was later named
superintendent. In July 1995, Mr. Agostini was awarded his present position by the board
of directors of Petrobras.
Edward
P. Heerema, President, Allseas, earned an MS
degree in civil engineering from the Technical University of Delft in 1974. Subsequently,
he joined the R&D department of his father's company Heerema Engineering Service. In
later years he was appointed department manager, then general manager, in which function
his prime responsibilities were development of new technology and business development.
After his father's death in 1981, he was appointed president of Heerema Holding Co., a
position he held until December 1984. He founded Allseas in January 1985. The company
operates the pipelay vessels Lorelay and Solitaire and the trenching support vessel
Trenchsetter; it has offices in Switzerland, the Netherlands, Belgium, Great Britain, the
U.S., Canada and Malaysia.
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