Achieving Zero Flaring in Offshore Gas Fields

ConocoPhillips is developing the Peng Lai field in Bohai Bay offshore China with six wellhead platforms (WHP) in 28 m (92 ft) of water. Phase I entailed one 24 slot WHP and a leased FPSO that has been in production since 2002. Phase II will have five 40 slot WHP's and a permanent FPSO. Phase II production began in 2007. The 24 inner slots of four of the Phase II WHP's will have 20″ drive pipe conductors and the 13 3/8″ surface casing will be installed by drilling with casing. The 16 outer slots, 8 on the north row and 8 on the south row, will have 36″ drive pipe conductors and provide dual bore 13 3/8″ surface casing strings in each slot. These holes will be directionally drilled at a slight angle to facilitate subsequent directional drilling. The 56 wells drilled from a 40 slot WHP reduces the size and cost of the platform while providing additional wells to meet the reservoir development plan. A portion of the wells will be "pre-drilled" from a jack-up through the WHP jacket while the topsides are under construction. The 13 3/8″ surface casing strings, using both the drill with casing and dual bore methods, are installed during batch setting programs. The jack-up pre-drills wells below surface casing until the topsides installation begins, at which time the jack-up moves to the next platform and repeats the process. After the topsides are installed on the WHP, a self contained platform rig continues the drilling and completion program. The drilling program on the last WHP, to be installed in 2009, will be conducted exclusively from a platform rig, including the 13 3/8″ drill with casing program in all 40 slots. This paper will describe the well construction program as part of the field development plan, the installation procedures, results of the surface casing installation programs and the drilling cost savings realized as a result of using drill with casing and dual bore conductor technologies.

Flare and relief systems are inherently dynamic process. Relief devices (PSV, rupture disc and flare tips) depend on system pipage for specified performance. These dependencies cause both transitory and lasting impacts. These impacts can only be understood by dynamic analysis. The past 10years of application confirm the need for and credibility of dynamic models. This paper details the theoretical development, validation and utilization experience of flare system dynamic models. INTRODUCTION Steady state flowsheet simulators are fairly routine software in today's processplant design environments. Pipeline transients and control system design are recognized dynamic problems and are best analyzed by simulation. However, dynamic simulation is still infrequently practiced. with cost to benefit ratio rapidly in favor of computerization, applications of dynamic simulations in process industries will undoubtedly multiply into the future. This paper describes a class of design problems in which we saw advantage in applying dynamic simulation oil field flare systems are inherent dynamic processes. Relief devices depend on system pipage for specified performance - relief valve capacity dependent on discharge back pressure, header peak pressure dependent on rupture disc burst conditions, radiation imposed limits dependent on peak relief rate, flare equipment size dependent on relief load characteristics and particulars of the staging philosophy. These dependencies cause both transitory and lasting impacts, e. g. temporal overpressure, flow cycling, and flame out events. And these impacts can only be understood by dynamic analysis. The past 10years of application confirm the need for dynamic models and the credibility of this technology improved in close association with better understanding of the complex flare system interactions. FLARE SYSTEM DESIGN CONSIDERATIONS Flare systems are final safeguards against overpressure, during plant transient conditions. The flare system must be designed to relieve excessive pressure to insure safety, specifically not to exceed levels allowed by "Code". API Design Practice 520 & 521 are widely observed as voluntary guidelines on the design and operation of flare systems in the American Petroleum Industry. Two key concepts are particularly applicable to this work. "Pressure relieving devices are installed to ensure that a process system or any of its components are not subject to pressures that exceed the Maximum Allowable Accumulated Pressure." "Fail safe device and automatic equipment should not replace pressure relieving devices as protection for individual process equipment." The first paragraph specifies the requirement of relief devices in the protection of equipment against overpressure. The second paragraph further stipulates that pressure relieving devices cannot be replaced nor substituted. This second paragraph therefore excludes all but pressure relieving devices in flare systems. API (ASME) pressure relieving devices for flare systems are clearly defined as PSV (Pressure Safety Valve), rupture disc and flare tip. ASME section VIII, Div. 1 Code stipulates the pressure relief requirements on unfired pressure vessels.

Field results show that single or dual cycling diesel-electric generator sets combined with photovoltaics can realize up to 70% savings in fuel costs and 40% savings in maintenance costs over a conventional prime power diesel system. Targeted for remote power applications in the range of 200 to 50000 watt (average) load, this power concept takes advantage of the large peak-to-average load demand ratios encountered in these sites. This hybrid power system can be retrofit to existing power plants, providing an extremely cost effective solution to rising fuel and maintenance costs. Two system architectures, for DC and AC loads, are presented along with photovoltaics/diesel sizing considerations, battery sizing, component selection issues and the data on load vs cycle performance. Future trends in the remote power industry are outlined.< <ETX xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">&gt;</ETX>

Optimal scheduling of power transformers preventive maintenance with Bayesian statistical learning and influence diagrams

We have developed a method for statistical anomaly detection which has been deployed in a tool for condition monitoring of train fleets. The tool is currently used by several railway operators over the world to inspect and visualize the occurrence of “event messages” generated on the trains. The anomaly detection component helps the operators to quickly find significant deviations from normal behavior and to detect early indications for possible problems. The savings in maintenance costs comes mainly from avoiding costly breakdowns, and have been estimated to several million Euros per year for the tool. In the long run, it is expected that maintenance costs can be reduced with between 5 and 10% by using the tool.

Through the use of a High Integrity Pressure Protection System (HIPP$) the flare capacity of a well head platform can be reduced to the flowrate required for depressurisation. The HIPPS may also be used to reduce the are capacity of a process plant. By the use of HIPPS, the discharge of hydrocarbons or carbon dioxide due to venting/flaring is reduced. This paper describes the development of HIPPS for the Sleipner B-platform offshore Norway. A 20" multiphase pipeline is protected against overpressure by two 20" quick acting shut down valves (QW installed in series, instead ofpressure safety valves. The valves have been qualified for operation in well stream at a shut-in pressure of 336 bar, and have a closing time of 2 seconds. Each of the QSKS has independent, fail safe instrumentation circuits. A parallel rain of QSV.s has been installed due to the testing requirements. The estimated saving using HIPPS on SLB was $25 mill. The paper also discuss existing and new applications of the HIPPS. INTRODUCTION The Sleirmer Vest is a gas field, containing 33 billion Sm 3 of sales gas 29 million of code oil and; mill. tons of NGL. The development consists of two platforms, a wellhead platform (SLB), and a gas treatment platform (SLT). Platform production is 20.5 mill Sm3/Dof sales gas and 450 Sm3/hrof condensate(including NGL). Sleipner Vest will come on stream in 1996. The well head platform is connected to the treatment platform via a 20" multiphase pipeline. The Sleipner Vest interfiled pipeline has a design pressure of 160 barg, while the wellhead shut-in pressure on Sleipner B is 336 barg. It is therefore necessary to protect the pipeline against the wellhead pressure. The flowrate in the pipeline is 250 kg/s. The main scenarios for over pressure in the pipeline was considered to be hydrate formation, pigging and closing of the inlet valve on Sleipner T. A flare system designed for blocked outlet, i.e. fill flow, is Expensive at the high flow rate required (250 kg). It was therefore decided to use a HIPPS. The HIPPS on Sleipner B is shown in figure 1. PROBLEM DESCRIPTION For this paper HIPPS is defined to be a system for Over pressure protection of process equipment by utilizing dedicated shutdown valves. The HIPPS system protects the equipment against over pressure by closing down the source of the over pressure. HIPPS has been used offshore in production systems for several applications, mostly for tie-ins of new fields to existing platforms, or as a modification to platforms where the flare capacity is limiting for the oil production. A number of different valve types, instrumentation concepts, valve configuration etc. has been used. In terms of equipment, valve configuration etc. API RF'14C, ref. /1/, has traditionally been used for design of process safety systems offshore, but does not describe the application of HIPPS. Overpressure protection by the use of double shut down valves is permitted for wells, but the use of additional PSVS are still recommended by API.

Fatigue damage has been discovered in the conductor guide bracing of many of Mobil's Gulf of Mexico offshore platforms in water depths ranging from 62 to 432 feet. The damage varied from magnetic particle indications to total failure of the guides. Although the damage was found primarily in the uppermost underwater guides, cracks have been discovered in elevations as low as the -225 foot level. Inspection and analysis revealed the cause to be fatigue due to vertical wave loading. Although generally ignored in the past, vertical wave loading is now recognized as a major factor in conductor guide placement and design. This paper will discuss a simplified fatigue analysis method and various repair methodologies including weld profiling, internal grouting of members, removal of guides, bracing of guides, and the installation of stress grouted clamps. Twenty-eight multiwell drilling / production platforms were analyzed. They were all modern designs installed from 1972-1989 and ranging in water depth from 62 to 760 feet. Potential fatigue life problems were discovered in 23 of the 28 platforms analyzed, indicating that a problem exists in the current method of designing and placing conductor guides. An analysis method is presented that can predict potential fatigue damage before it occurs and without costly inspection methods. Economical repair methods are proposed that can be implemented before fatigue cracking occurs, resulting in significant savings in maintenance costs. This paper also includes guidelines for designing and placing conductor guides on new platforms. BACKGROUND The literature cites problems with fatigue cracking in the first level of submerged conductor guides, primarily in the North Sea as early as 1979. Table One contains a summary of these problems and solutions. The industry began to recognize the problem of fatigue due to vertical wave loading in conductor guides and began to recommend placement of the first submerged guide as low as possible.14 The first problem with conductor guides in Mobil's Gulf of Mexico platforms occurred in 1975 when a -20 foot elevation guide fell out of the East Cameron 286-A platform after a hurricane. The platform was only three years old. Although not noted at the time, it was most certainly accelerated by fatigue due to vertical wave forces. Vertical particle motions had been accounted for in the static design, but their magnitude was negligible. In 1981 cracking was discovered at the -28 foot elevation conductor guides on High Island A 573-A, B and A 572-C platforms. Repairs, consisting of tieing the guides to he conductors were completed, however the guides failed again and were removed. The cracks were surface cracks at the six and twelve o'clock positions, indicating that they were caused by fatigue due to vertical wave forces. Further inspections revealed problems at many of the uppermost underwater guides, some with as little as two years of service. The -27 foot elevation conductor guide at West Cameron 617-A platform completely failed and dropped out of the platform in 1985 after nine years of service.

Structural health monitoring, as a non-destructive damage detection technique, has beenadopted by many researchers as well as various industries to keep up with the increasingdemand for preventive maintenance routines. Oil and gas is one of the major industries inwhich effective damage detection can ensure reliable transportation of chemicals andprovide tremendous savings in maintenance costs. The present work investigates theintegrity of a novel damage detection method through a set of experiments conducted ona standard steel pipe commonly used in the oil and gas industry. The methodinvolved collection of the vibration signature of the pipe via certain sensors, anddecomposition of the signature (signals) by empirical mode decomposition. This wasfollowed by the use of a damage index defined on the first intrinsic mode functionresulting from the decomposition. The experiment consisted of a cantilever steelpipe equipped with piezoceramic sensors to monitor the free vibration of a pipeimpacted by an impulse hammer. Three damage cases were studied including singlehalf-circumferential, single full-circumferential, and multiple circumferential andhalf-circumferential damages. A MATLAB code was developed to process and todecompose the signals according to the proposed methodology. The results showed that theproposed damage detection methodology could successfully detect the presence andlocation of damage, and could also identify the severity of the damage. A set ofexperiments was also done to examine the effect of support flexibility on thedamage index, and to examine the sensitivity of the method to support conditions.

Design optimization of a large municipal solid waste incinerator

The current generation of aircraft coatings had its basis in the polymer technologies of the 1970s and the use of chromate-based metal pretreatments and primers. There have been some incremental improvements in the epoxy and polyamide oligomers used in the primers as well as the isocyanates and flexible polyols used in topcoats, plus increases in the volume solids of the coatings to continue minimally meeting environmental requirements, but no truly new technologies have been developed and applied to aircraft coatings since that time. However, because of increasing economic and environmental pressures, this situation will soon change. Also, the U.S. Air Force is seeking a coating system that will have an ultimate lifetime of 30 years for maintenance cost control and fleet sustainability. The first change in the present coatings system will be in the pretreatments plus primers that currently constitute the metal protection system for the high strength Al alloys used for aircraft. For military aircraft, these alloys will continue to be Al 2024 T-3 and Al 7075-T6, heat-treated metals that have phase-separated regions rich in reactive metals such as Cu, Mg, and Zn. There are several new technologies now under consideration for such metal protection including conductive polymers as primers without Cr-based metal pretreatments, sol-gel based pretreatments and primers, plasma polymer metal pretreatments, and organo-modified aluminum oxide particles. Each of these technologies has shown some promise for Cr replacement, but each presently has a weakness that needs to be corrected for immediate usage. For the topcoat system, fluorinated polyols and improved use of UV-absorbers and light stabilizers will probably be the first changes implemented, with ceramer and other new crosslinking systems the most likely next polymer matrix candidates. The target for the entire coatings system is to have drastically improved wet-adhesion due to a covalently bonded system that has a gradient in composition that goes continuously from metal to metal oxide to mixed metal oxide/organic polymer to high-performance UV-stable organic polymer. The materials cost for such a system may be quite high, but the maintenance cost savings will much more than offset these costs.

Legacy gas fields face major challenges in field development planning, particularly in overcoming economic viability constraints caused by limited reservoir resources. Various cost-reduction initiatives have been undertaken. COMPANY has successfully implemented one such strategic initiative, which aims to maximize the lifespan of existing assets by repurposing wellhead platform topsides. Building on the success of reused two wellhead platform topsides in Great Bongkot North field and one wellhead platform topsides in Arthit field. These projects have extended platform life and provided significant cost savings and operational efficiencies. These successes serve as a strong foundation for future Topside Reuse initiatives. Future opportunities have been identified, and key insights from these initiatives have been analyzed. Lessons learned, technical assessments, and cost optimization of topside reuse can be integrated into other legacy gas field's master plan to enhance efficiency and sustainability in the oil and gas industry. A comprehensive Topside Reuse Screening initiative conceptual study was conducted to evaluate the feasibility and suitability of reusing existing wellhead platform topsides in the Gulf of Thailand. This initiative involved assessing technical aspects, which served as the foundation for potential modification work. High-level cost estimations were performed to provide a clear financial perspective on reuse of topsides. To evaluate topside reuse, a screening database and assessment tools were developed to identify modification costs if the topside is reused, categorized into base, recommended, and optional costs. These tools provide a comprehensive financial view and help determine topside reuse candidates in line with the depletion plan. The final donor and receiver candidate wellhead list is determined and developed into a Topside Reuse Master Plan for maximizing benefit to asset. The strategic depletion plan implementation with the reuse of existing wellhead platform topsides presents significant opportunities to reduce capital investment and operating expenses, particularly in maintenance, inspection, and decommissioning. By reusing wellhead topsides, we can enhance the value of existing assets and improve economic viability in mature fields. Key finding of this study is potential for substantial cost savings. With appropriate matching between reused topsides (donor) and designated platforms (receiver), and required minimal modifications, cost savings of approximately 5 - 10 million USD per new wellhead platform can be achieved. This estimate underscores the financial viability and attractiveness of the topside reuse strategy for field development with enormous benefit regarding the numbers of topside reuse. In conclusion, the topside reuse screening initiative conceptual study demonstrates that reusing existing wellhead platform topsides is a viable and economically beneficial strategy. Leveraging existing infrastructure can achieve significant cost savings, enhance asset value, and promote sustainable practices. Developing the Topside Reuse Master Plan, guided by this study's findings, will be crucial in realizing these benefits and ensuring the successful implementation of this strategy in the Gulf of Thailand. This is an attractive initiative and proactive approach that serves as a key success enabler in overcoming the challenges of legacy gas fields, particularly those with marginal resources and declining margins. Moreover, this innovative practice can be adopted and applied by other operators in oil and gas industry who are facing same challenges.

ABSTRACTDownhole drilling motor is one of the equipment used for drilling and they perform the task of directional drilling. The rotor of these motors is made of 17-4 PH steel, which is generally coated with hard chromium. In this study, the feasibility of replacing hard chromium with WC–20Co–1Ni using a high velocity oxygen fuel system was examined. The result of the metallurgical and mechanical examination showed that changing of the coating to WC–20Co–1Ni improved the wear performance and increased the lifespan of the rotor. In addition, the chemical resistance to corrosion due to the influence of the corrosive gases in the hole on the rotor improved significantly. Finally, substitution of the hard chromium coating with the WC–20Co–1Ni caused an increase in the lifespan and performance of the downhole motor in extreme environmental conditions of the drilling formations, which led to economic savings in amendment and maintenance costs.

The New Jersey Department of Environmental Protection (NJDEP) has partnered with the Union County Utilities Authority (UCUA) to establish a demonstration project for the collection and demanufacturing of consumer electronic appliances (CEA) generated within Union County, NJ. Obsolete electronic products are used to generate components for the manufacture of new products, with benefits including diversion of CEA from the UCUA incinerator (with attendant reductions in lead and cadmium emissions by the facility), management of these items as a universal waste-thereby controlling the metals found in CEA in an environmentally sound manner, job creation, and potential savings in operations and maintenance costs at the Union County Resource Recovery Facility.

We have witnessed low resource utilization of high performance graphics workstations in our instructional computer laboratories. The low utilization statistics indicate that workstation consolidation could achieve great savings in infrastructure, networking, power consumption, and maintenance costs. In addition, we would spend less time in deployment, security, and fault isolation without compromising performance. The basic enabler for workstation consolidation in our instructional computing environment is the ability to allow multiple separate operating system instances and associated software packages to share a single hardware server. We have successfully utilized existing off the shelf products and developed tools and protocols to migrate processing tasks from the desktop level to the virtual desktop level running on remote hardware and returning the processing results back to the desktop level for display. Since all processing is done at the server level, we no longer need high performance graphics workstation class machines at the desktop. This allows us to offer high performance graphics workstation capabilities to any desktop, including lower-end commodity class desktop machines, notebook computers, or even thin-clients. While server consolidation through virtualization is not new, desktop workstation virtualization seemed a natural and novel extension of the server virtualization framework. Indeed, the general trend is towards applying virtualization techniques to almost all Information Technology infrastructure machinery, and we should expect to see more virtualization, virtually everywhere in higher education institutions. In this report, we will present our approach, framework, implementation challenges, lessons learned and next steps.

The reuse of wellhead platforms becomes the new strategy as the offshore oil and gas industry pursues cost-effective, sustainable solutions for field development and decommissioning. In the Gulf of Thailand, many platforms have reached end-of-life, repurposing infrastructure offers major economic and environmental benefits. The relocation of pile through-legged jackets is the first of its kind in the SEA region. This innovation results in major reduction of Capital Expenditure (CAPEX), less decommissioning activities while Operating Expenses (OPEX) is minimized. A wellhead platform integrity assessment was conducted to verify the jacket's suitability for reuse, following the Structural Integrity Management (SIM) process using Risk-Based Inspection (RBI) strategy in compliance with API RP 2SIM guidelines. According to API RP 2A, key technical considerations included structural analysis, corrosion management, and designing a new mudmat template not only to accommodate varying water depths and challenging soil conditions but also to reduce offshore modifications. The reuse of appurtenances such as risers and pile sections is included. Transportation and towing methods, including vertical offshore-to-offshore wet tow by Heavy Lift Vessel (HLV), were code checked with Subject Matter Expert (SME) collaboration. The reuse of the wellhead platform has demonstrated significant cost savings, environmental benefits, and innovation in offshore field development. By repurposing the existing Wellhead platform, CAPEX was 25% reduced when comparing to constructing new structures. Environmental impact was minimized by avoiding extensive decommissioning activities by reducing one cycle and preserving the surrounding marine life ecosystems. The pre-installed self-penetrating mudmat template at new receiver location before installing the reused jacket on top spotlights the innovation method reducing offshore construction time and work complexity. The vertical wet tow method by HLV with 15-meter submerged section of jacket enhances the safety level along the towing route which could have subsea assets in place, while maintaining the jacket structural integrity within risk acceptable threshold with 24 well slots at a new 74-meter water depth. Overall, the project validates that jacket reuse is a viable and sustainable strategy for future offshore developments in soft seabed region. This approach offers a remarkable and repeatable model for similar infrastructure in other aging or late-life offshore fields. The reuse and relocation of conventional pile through-legged jacket demonstrates the first of its kind aligning with the regional industry trend for cost efficiency and sustainability within the oil and gas sector. This approach reduces the new fabrication, minimizing material consumption and environmental impact. The project delivers a 25% life-cycle cost reduction and reduces the hydrocarbon footprint over 50%, positioning it as a new model for new development innovations and decommissioning alternatives.