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Floating Liquefaction Natural Gas units, or FLNGs, have matured as a technology in recent years with Petronas, Golar, Shell and Exmar units coming on-line. Additional units from Petronas and ENI are under construction.
The challenge with integrating elements of onshore LNG production plants, LNG shipping and offshore floating production and offloading (FPSOs), into one floater with limited space and load bearing capacity, was significant, necessitating the development of design guidelines.
The traditional approach to mitigating the impact of fire and explosion risk in an onshore LNG plant is to use physical separation between the various elements of the plant. In addition to potentially reducing fire ignition and escalation potential, this can facilitate personnel egress and allow for additional leak containment to be incorporated.
With production, liquefaction and storage integrated in one unit, there is very limited opportunities for using space segregation as a safety measure within the unit. Also, when the cryogenic fluids offload to an LNGC in a side by side configuration with the FLNG there is also no opportunity to segregate the loading carrier from either LNG storage, production or liquefaction.
With this background, regulatory regimes and class societies have leaned heavily on the guides and rules for FPSOs and integrated significant elements from LNG shipping, particularly when it comes to LNG cargo containment and offloading.
Every potential FLNG location with corresponding metocean and meteorological data as well as fluid flows and compositions will be different, so it is very difficult to create prescriptive rules for separation distances etc. As a result, it is typical to quantify and mitigate risk through analysis and studies and use the ALARP (As Low As Reasonably Practical) principle when reviewing risk mitigation efforts.
This paper will show how the different standards and rule sets are brought together as a comprehensive regulatory approach. Standards and class rules are utilized to bring together an approach that results in a design and construction that satisfies the needs of flag, class, coastal state and owner. To this date floating LNG facilities have been able to safely carry out commissioning and start up and produce and deliver cargos without major incidents. The track record to date also highlights how the technology can be used in harsher climates and seas and hence can unlock more gas reserves.
As a result of its investigation into the incident and its findings, the bureau recommends that operators increase scrutiny in the design, placement, and maintenance of their subsea infrastructure. The Bureau of Safety and Environmental Enforcement is launching a safety initiative to bring critical information directly to offshore workers on the outer continental shelf. The BSEE!Safe program uses text messages to send links to its published Safety Alerts and Bulletins. The Bureau of Safety and Environmental Enforcement says its final well-control rule removes unnecessary regulatory burdens to responsible offshore development while maintaining safety and environmental protection. The Bureau of Safety and Environmental Enforcement says its staffing and inspections are up, while the environmental group Oceana says that oil and gas drillers have a financial incentive to ignore safety.
Operators have established procedural requirements as part of their HSE, risk and cost control policies. Automating procedural compliance enables real-time operations oversight while reducing risks associated with manual processes. A novel technique was developed and implemented to automatically check rigs’ procedural compliance with an operator's guidelines and alert users in real time.
The following procedures have been developed and deployed: zeroing of weight on bit and mud motor differential pressure for more accurate ROP (rate of penetration) optimization, lowering BHA (bottom hole assembly) back to bottom with reduced RPM, connection practice procedure, and capturing steady-state hook-load values for improved torque and drag monitoring. Each procedure was identified to influence future optimization efforts to a varying degree. Consider if the weight on bit is not zeroed properly it can cause incorrect driller's road-map recommendations for new wells.
The framework has been extensively tested and refined with the assistance of a Permian operator until it reached an acceptable accuracy: 95% for back-to-bottom procedure, 99% for zeroing WOB (weight on bit), and 90% for zeroing DIFF (differential pressure). Reports have been generated to display the statistics of the compliance for each rig and crew. A Permian operator, who has field tested the procedural compliance application, estimates that it will save millions of dollars per year by avoiding costly equipment damage as well as from significant time savings by standardizing a back-to-bottom procedure.
Real-time procedural compliance is a novel technique to check whether the rig personnel follow the operator's procedures. It has a flexible back-end interpreter, and each procedure is provided separately. This ensures the procedure is not attached to the original code and can be easily modified. Through the use of a real-time compliance engine, every operator can load their respective procedures and check for compliance in real-time.
Many of the oil reservoirs in ADNOC’s portfolio have been producing for decades and continue to deliver their target rates, thanks to development schemes centred on pressure support from peripheral water injection and/or crestal gas injection, where applicable, or from line-drive patterns.
As these reservoirs mature, a number of enhanced oil recovery (EOR) techniques are being evaluated to increase the ultimate recovery factor. Choosing one or several appropriate EOR methods starts with a robust screening methodology, which in this case has to apply across an entire reservoir portfolio, rather than just to a single asset.
The key objective of the screening efforts presented in this paper is to estimate the EOR potential from each reservoir in a systematic manner to allocate the right resources, to the right fields, at the right time, with the right technology. Therefore, the screening methodology must take into consideration the following aspects: The focus of the screening is on identifying opportunities, which are or will become technically feasible by the time deployment is required The screening procedure must remain sufficiently high-level to be able to deliver an outcome within a short time-frame A single EOR method is not necessarily applicable across an entire reservoir; hence several EOR methods can potentially be implemented in the same reservoir but in different areas The thought process (workflow) has to be properly documented so that the screening exercise can be updated whenever new technologies or new relevant field data become available
The focus of the screening is on identifying opportunities, which are or will become technically feasible by the time deployment is required
The screening procedure must remain sufficiently high-level to be able to deliver an outcome within a short time-frame
A single EOR method is not necessarily applicable across an entire reservoir; hence several EOR methods can potentially be implemented in the same reservoir but in different areas
The thought process (workflow) has to be properly documented so that the screening exercise can be updated whenever new technologies or new relevant field data become available
The new EOR screening tool considers more EOR methods compared to previous screening efforts: It takes a much broader view on potential source gas options for miscible gas injection, namely enrichment of sweet hydrocarbon gas, sour gas streams, CO2 with or without impurities, as well as nitrogen for some high-temperature reservoirs containing volatile oil. This step involved estimating miscibility conditions for hundreds of combinations of injection gas compositions and reservoir fluids using equation-of-state based MMP calculations in addition to common MMP correlations. The reservoirs are all carbonate formations and are characterized by high temperature and high salinity. These conditions have traditionally been a challenge for chemical EOR methods involving polymers and surfactants. However, recent R&D progress has opened up for opportunities not previously considered. Both polymer and foam agents are currently being piloted, which have the potential to change the EOR landscape in Abu Dhabi and perhaps elsewhere as well. As reservoirs mature and breakthrough of injection fluids begin to occur, the need for improved reservoir conformance becomes evident. The success of any EOR technique relies on the right well placement with the right monitoring in place and the right level of injection profile control.
It takes a much broader view on potential source gas options for miscible gas injection, namely enrichment of sweet hydrocarbon gas, sour gas streams, CO2 with or without impurities, as well as nitrogen for some high-temperature reservoirs containing volatile oil. This step involved estimating miscibility conditions for hundreds of combinations of injection gas compositions and reservoir fluids using equation-of-state based MMP calculations in addition to common MMP correlations.
The reservoirs are all carbonate formations and are characterized by high temperature and high salinity. These conditions have traditionally been a challenge for chemical EOR methods involving polymers and surfactants. However, recent R&D progress has opened up for opportunities not previously considered. Both polymer and foam agents are currently being piloted, which have the potential to change the EOR landscape in Abu Dhabi and perhaps elsewhere as well.
As reservoirs mature and breakthrough of injection fluids begin to occur, the need for improved reservoir conformance becomes evident. The success of any EOR technique relies on the right well placement with the right monitoring in place and the right level of injection profile control.
Pillars of the Industry features select contributions from experienced authors who have distinguished themselves by prolific careers and have made significant contributions to their fields of specialization. It is intended that readers find a source of inspiration that could help them shape their own contributions to the industry. In this issue, we have invited Michael Economides of the U. of Houston and Brian Glass and Carol Stoker of NASA's Ames Research Center to contribute to the discussion about peak oil and hot technologies. Economides explains why he is prudently optimistic about the world energy situation. He asserts that even though peak oil is a distinctive attribute of any depletable resource, it might never come to fruition in the case of oil.
Shale resource development activities have been in the headlines for the past several years in the world media, especially in North America. It is tempting to think that developing a shale play is a matter of obtaining acreage, applying the latest in horizontal well drilling and multistage fracturing, and monitoring handsome produced gas volumes. Unfortunately, like most other business investments, it is not that simple. There are three constraints: economics, regulations, and politics. With today's depressed natural gas prices, the development of shale gas can be economically marginal in the near term.
ABSTRACT: A fracture network model provides a wealth of information concerning the characteristics of a rock mass, including fracture intensity, block size, and connectivity. This paper identifies methods to utilize information derived from DFN models. The fracture intensity of a DFN can be analysed for individual or grouped subvolumes of the model. A DFN is discretized into volumetric elements (voxels). Stochastic DFN models measuring 25 × 25 × 25 m3 are modeled with identical attributes. Fractures are modeled as non-planar and non-persistent, and orientations varied to generate a variety of block shapes and sizes. The voxels used for metrics analysis range in size from 1 m3 to 1 953 m3, representing from 23 to 253 voxels. Fracture intensity is measured as a P32 value for all elements. The coefficient of variation (CV%) of fracture intensity is calculated for each voxelization to generate a curve characteristic of a particular DFN model. An estimate of the in situ block size distribution (IBSD) is made by considering the number of unfractured voxels (null blocks). The fracture intensity, CV% of fracture intensity and IBSD values derived from these DFNs can be used as input to a variety of secondary models.
The MoFrac discrete fracture network (DFN) modeling software (MIRARCO, 2019) implements a rules-based methodology to generate plausible fracture networks guided by information derived from mapped data. (Junkin, et al., 2017; 2018). DFN models can range from entirely stochastic to highly constrained to known data. Information concerning the characteristics of a rock mass can be derived from a DFN model; this includes, inter alia, fracture intensity, block size, and flow connectivity. This paper demonstrates a method, through voxelization, to derive information regarding fracture intensity variability and in situ block size distribution (IBSD) of DFN models useful for incorporating into secondary studies such as hydrogeological flow, fragmentation, and slope stability analysis.
The sound bites after the release of the final version of the revised US offshore well control rule suggested big changes were coming soon. A statement from the environmental group Public Citizen said, “The Trump administration is once again putting corporate profits over safety by gutting the primary offshore drilling safety measure put in place to prevent the next massive oil spill.” In a speech covering the administration’s record on offshore regulation, Scott Angelle, director of the Bureau of Safety and Environmental Enforcement (BSEE), said that promoting “homegrown domestic energy is what we are going to be about.” Both comments were delivered shortly after the release of the final version of a revised well control rule, which clearly is a hot-button issue for many. It drew more than 100,000 comments from the industry and citizens, many of whom sent notes opposing changes to the 2016 rule.
For example, pressure-monitoring data were analyzed using a “physics-based” model able to distinguish between normal pressure changes and leaks, the presentation said. One slide showed how a pressure test allowed the partners to identify deteriorating elastomers in the annular preventer. The test results were confirmed when they found the parts were deteriorating during an inspection. In another case, Shell reported that an analysis of a part that had repeatedly failed led to a change in maintenance procedures to avoid damage that had occurred during previous repairs. This program saved Shell money by reducing downtime on the four, high-performance drillships, three of which were in Transocean’s fleet.