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Weighting agents or heavyweight additives are used to increase slurry density for control of highly pressured wells. Weighting agents are normally required at densities greater than 17 lbm/gal where dispersants or silica is no longer effective. This is the most commonly used weighting agent. Hematite is a brick-red, naturally occurring mineral with a dull metallic luster. It contains approximately 70% iron.
All raw natural gas is fully saturated with water vapor when produced from an underground reservoir. Because most of the water vapor has to be removed from natural gas before it can be commercially marketed, all natural gas is subjected to a dehydration process. One of the most common methods for removing the water from produced gas is glycol. This page discusses the types of glycols that may be used, the process used to remove water with glycol, and the control of air emissions from glycol dehydration units. The water vapor content of natural gas at equilibrium saturation is shown in Figure 1, which is based on the well-known McKetta and Wehe chart and expanded to 400 F on the basis of data of Olds, Sage, and Lacy. As can be seen, the water content increases with increasing temperature and decreasing pressure. When natural gas is a feedstock to a turboexpander plant for high natural gas liquids (NGL) recovery, virtually all the water must be removed before chilling the gas to very low temperatures. There are four glycols that are used in removing water vapor from natural gas or in depressing the hydrate formation temperature. Table 1 lists these glycols and shows some of the properties of the pure material. Ethylene glycol (EG) is not used in a conventional glycol dehydrator, as described below. The main use of EG in the dehydration of natural gas is in depressing the hydrate temperature in refrigeration units. Tetraethylene glycol would have to be regenerated at higher temperatures than TEG to reach the required purity for application in a glycol dehydration unit. Thus, of the four glycols, TEG is the best suited for dehydration of natural gas. In glycol dehydration, TEG is usually referred to only as "glycol."
A single-step cryogenic-distillation process that removes carbon dioxide (CO2), hydrogen sulfide (H2S), and other impurities from natural gas has been developed by ExxonMobil. Rather than avoiding the freezing of CO2 at cryogenic temperatures, solidification is allowed to take place in a very controlled fashion. The technology has potential to separate CO2 and other impurities from natural gas and to discharge these contaminants as a high-pressure liquid stream. Meeting the demand for natural gas will require new resources. Many of those new resources will contain substantial amounts of CO2 and H2S that must be managed properly at the surface along with the produced hydrocarbons.
Conventional deaeration of seawater for water injection use expensive chemical scavengers and heavy vacuum towers, which occupy valuable space on offshore installations. The scope of this study is to investigate, compare, and further advance the development of two state-of-the-art deaeration technologies which solve the aforementioned issues. The first method, compressorless deaeration with the use of stripping gas is a newly developed modification of an already efficient, light, compact, and worldwide implemented technology. This technology uses pure nitrogen in a regeneration loop, together with static mixers which allow oxygen mass-transfer from seawater into the gas phase. The second method utilize the same proven nitrogen regeneration loop in combination with novel membrane deaeration technology.
Advanced dynamic process simulations, combined with field data, mechanical design and process calculations are utilized to quantify process parameters and design requirements for the two technologies. The results are presented and used for discussing advantages, disadvantages, possibilities and further development needs of both the stripping gas- and membrane technology.
Results show that it is possible to further increase the robustness of the stripping gas-technology by eliminating the compressor. A clever ejector system with turn-down capabilities ensures the technology's advantage of positive operating pressure and utilizes energy from the seawater flow to compress the nitrogen. Power calculations, turn-down possibilities and oxygen removal efficiency at various operating conditions are presented. A suggested design for membrane deaeration is also presented, along with calculations and comparisons to the stripping gas technology, especially regarding flow rate capacity and the economies of scale. The main advantage of the proposed membrane technique compared to existing membrane concepts is the high-purity nitrogen regeneration loop, which offers improved mass-transfer capabilities across the membrane.
The novelty of this work the feasibility of successfully operating a compressor-less, efficient, compact deaeration system on positive pressure. Additionally, the stripping gas technology requires no chemical scavengers in order to obtain an oxygen concentration lower than 10 ppb. The membrane deaeration process can also achieve low oxygen concentrations without chemical scavengers and it is further found that the technology might be economically viable compared to stripping gas for low flow rates.
Ramnath, Jonathan (University of Trinidad and Tobago) | Felix, Elroi (University of Trinidad and Tobago) | Shah, Ahmid (University of Trinidad and Tobago) | Soroush, Mohammad (University of Trinidad and Tobago) | Omokughegbe, Nykesi (University of Trinidad and Tobago) | Jaipaulsingh, Francis (University of Trinidad and Tobago)
Abstract Decreasing oil production and increasing quantities of greenhouse gases continue to be an issue plaguing Trinidad and Tobago's energy sector. While CO2 EOR has been proven to be an effective solution to both of these problems it is often overlooked in Trinidad due to the inability of the gas to achieve miscibility with the crude oil as well as operational limitations such as an absence of transportation pipelines for the CO2. Even though miscibility may not be achieved, immiscible CO2 EOR can effectively increase production and sequester CO2 resulting in an increase of revenue as well as decreasing the quantity of greenhouse gases vented to the atmosphere. This paper aims to highlight the possibility of implementing immiscible CO2 projects in Trinidad. The scientific processes that are responsible for increased crude oil production are discussed and the operational considerations for a safe and economically feasible project in Trinidad South West fields are examined. It was seen that the vaporizing gas drive process would not result in miscibility in the shallow low pressure fields of the South West Trinidad however it would cause a significant reduction in the interfacial tension, this in turn causes an increase in the capillary number which would result in additional oil recovery. It was also found that the high viscosity of the non-carbonated oil of the region would result in an even greater reduction in viscosity when it is mixed with the CO2 gas resulting in more favourable oil mobility. The high solubility of CO2 in hydrocarbon liquids result in the swelling of crude oil. In the water wet formations, the oil within the pore spaces swells, resulting in an increase of relative permeability aiding in additional oil recovery. In the field evaluated, it is proposed that the CO2 be acquired from Atlantic LNG, tube trailers be used to transport the CO2, 100mmscf of gas injected per day with a 5spot injection pattern and the produced gas compressed and reinjected. From simulation this was found to produce an additional 389,360bbls of oil where CO2 would be sequestered and an additional profit of US$ 21,414,800 would be acquired within a 20 year period.
Bonnereau, Julie (TOTAL S.A.) | Weiss, Claire (TOTAL S.A.) | Delannoy, France (Air Liquide Engineering & Construction GmbH Germany) | Linicus, Matthias (Air Liquide Engineering & Construction GmbH Germany) | Jüngst, Eckhard (Air Liquide Engineering & Construction GmbH Germany) | Terrien, Paul (Air Liquide Engineering & Construction GmbH Germany)
Abstract Oil and Gas operators are more and more interested in developing and improving native CO2 recovery technologies as capturing native CO2 can drastically reduce the greenhouse gases emission and at the same time can be valorized for enhanced oil recovery. While considering CO2 emission from a gas plant, native CO2 significantly contributes to the total amount. Usually when natural gas contains both CO2 and H2S, they are removed together and sent to an air fueled Sulfur Recovery Unit (SRU) resulting in a tail gas containing mainly nitrogen and CO2. The native CO2 can then be separated by the use of a chemical solvent such as Monoethanolamine (MEA) for example. TOTAL and Air Liquide Engineering & Construction have developed and patented an innovative process scheme for recovering the native CO2 and reducing the overall operating and investment costs of such process. This patented innovative process scheme consists in a Claus unit, fed with pure oxygen or enriched air instead of air, which leads to a tail gas stream containing mainly CO2 and H2 but no or only little nitrogen. A CO2 purification unit allows a CO2 rich stream to be recovered with a purity level reaching even 99.9%, while producing valuable by-products such as pure nitrogen and a hydrogen-rich stream, both of which can be used as utilities in other process units depending upon selected technology. This also reduces continuous emissions from the gas plant by eliminating the continuous operation of an incineration system. The CO2 purification unit can be either membrane, cryogenic or adsorption technologies. This paper also discusses the integration of the technologies of Air Liquide Engineering & Construction: OxyClaus, Tail Gas Treatment Unit (TGTU) and CryoCap, a very efficient CO2 purification technology. The scheme has been studied in detail for specific application to optimize the overall integration. It has been also compared to conventional CO2 capture schemes.
Boock, A. E. (Shell International E&P Co.) | Brinsden, M. S. (Shell International E&P Co.) | Sokolove, C.. (Hunting Titan Ltd) | Golian, T. G. (Hunting Titan Ltd) | Maienschein, J. L. (Lawrence Livermore National Laboratory) | Glascoe, E. A. (Lawrence Livermore National Laboratory)
Abstract Explosive thermal stability is an important topic for oilfield perforating operations and impacts perforating system performance and safety. Explosives have time dependent temperature limits which can lead to thermal decomposition when exceeded and, under some circumstances, can result in performance losses and safety hazards. Explosive thermal stability information is currently provided by perforating system manufacturers through time versus temperature plots. While these plots have proved useful for many years, this review of current industry thermal stability data and practices aims to highlight a need for improvement and expanded testing representative of the energetic materials as used in actual well environments. More specifically, this review discusses the potential economic impact on well performance and operational safety when thermal stability limits are exceeded. When using currently available time versus temperature plots, operators sometimes must select lower performing explosives which are thermally stable at higher temperatures especially for high temperature well environments. As a result, operators risk optimal well inflow performance with significant economic impact. Furthermore, exceeding the time dependent temperature limits can lead to thermal decomposition. Off-gassing from thermal decomposition can trap pressure inside of gun carriers creating safety hazards during misruns. This review includes a reference to a known occurrence where overexposure to temperature led to thermal runaway and a surface explosion of a recovered perforating system. Additionally, this review discusses shortcomings in thermal stability test methods and related API recommended practices. Current methods assessing thermal stability, including vacuum thermal stability, ampule, and ODTX (One Dimensional Time to Explosion) tests tend to use unrealistic test conditions. The API recommended practices do not directly assess thermal decomposition which is important in developing safe practices for recovered perforating systems which may have been exposed to temperatures exceeding thermal stability limits. This review concludes with recommendations for future work to better understand thermal stability in oilfield explosives. More suitable thermal stability tests which evaluate oilfield explosives in well environment conditions will lead to improved safety recommendations and has the potential for significant economic impact on well productivity through enhanced understanding of the time dependent temperature limits. Finally, this paper draws on the urgent requirements of the Operator community, the experience of the manufacturing community and the advanced technical support of a US National Laboratory to provide a concise review and recommendations which can then be promulgated through the API, as a major step in enhancing safety and ultimately well performance.
Abstract While considering CO2 emission from a gas plant, native CO2 significantly contributes to the total amount. Capturing this native CO2 can reduce a lot the green house gases emission and captured CO2 can be valorized for Enhanced Oil Recovery. Due to this, Oil and Gas operators are more and more interested in improving native CO2 recovery technologies. Usually when natural gas contains both CO2 and H2S, they are removed together and sent to Sulfur Recovery Unit resulting in a tail gas containing mainly Nitrogen and CO2. CO2 can then be separated by use of solvent (using MEA e.g.). TOTAL and Air Liquide have developed and patented an innovative process scheme recovering native CO2 and reducing the operating and investment costs. Claus unit fed with pure oxygen instead of air leads to a tail gas stream, containing mainly CO2 and H2. Then, CO2 purification unit allows recovering a CO2 rich stream with purity even up to 99.9%. This purification unit can be either membrane, cryogenic or adsorption technologies, or a combination of them. This paper also discusses about the integration of Oxygen-based Claus technology (OxyClaus), tail gas treatment unit (TGTU) and CO2 purification. The scheme has been studied in detail for specific application to optimize the overall integration. It has been also compared to conventional CO2 capture scheme to highlight its benefits leading to significantly lower CO2 recovery cost. This scheme contributes in many aspects to the current technical knowledge which may include low-cost CO2 capture, use of pure oxygen in the Claus, CO2 purification for EOR etc. Other benefits also include the size reduction of the Claus/TGTU, production of nitrogen stream to be valorized and separated H2-rich stream from CO2 purification unit. This paper will comprise the overall scheme description and discuss some results for the specific case study.
Abstract Controlled Freeze Zone™ is an efficient single-step cryogenic distillation process for the removal of carbon dioxide, hydrogen sulfide and other impurities from natural gas. Rather than avoiding the freezing of CO2 at cryogenic temperatures, the solidification is allowed to take place, albeit in a very controlled fashion. The technology has shown the potential to more efficiently and cost-effectively separate carbon dioxide and other impurities from natural gas, and to discharge these contaminants as a high-pressure liquid stream ready for underground injection, either for enhanced oil recovery applications or for acid gas injection disposal. Introduction Natural gas is the cleanest burning hydrocarbon fuel available and its growing demand is only projected to rise throughout this century. ExxonMobil anticipates total global energy demand to grow 35% by 2040 relative to 20101. Greater demand for electricity accounts for more than half of this increase. The clean burning characteristics of natural gas and its increasingly competitive economics for power generation are driving its expanded use in electrical power generation. Natural gas emits up to 60 percent less CO2 than coal when generating electricity, which becomes quite significant as costs arising from greenhouse gas policies mount. ExxonMobil forecasts natural gas to emerge as the leading source of electricity generation by 2040, and to become the second largest global fuel by 2040 behind oil, displacing coal from the second spot.
Abstract Abu Dhabi Company for Onshore Oil Operations (ADCO) has recently commissioned the first ever CO2-EOR pilot in the Middle East in its Rumaitha field. The main objective of the pilot project is to evaluate the feasibility of CO2 injection as a potential enhanced recovery technique. If the pilot is successful, ADCO will use CO2 to replace the hydrocarbon gas currently being injected in the field. In order to assess the impact of large scale CO2 injection on the field’s facilities, an engineering study was conducted. This paper discusses the methodology and main features of this study. Topics covered include: description of the field facilities; technologies for the separation CO2 from associated gas, key design parameters, study methodology, impact on existing facilities and the study findings.