Screening CO 2 storage options in The Netherlands

The Persian Gulf and its coastal areas are recognized as one of the biggest hydrocarbon basins in the world as world's largest petroleum reservoirs are located through its offshore and onshore oil and gas fields. Coastline countries of the Persian Gulf produce about 25% of the world's oil yearly and they have nearly two-thirds and one-third of the world's crude oil and natural gas reserves, respectively. In the Persian Gulf and south of Iran, Zagros orogeny process has a most important structural role as it causes many petroleum reservoirs into folds with northwest-southeast trends that are parallel with Zagros orogeny direction. However, there is good potential to explore new petroleum reservoirs in the Persian Gulf yet. One of these potential oilfields located northwestern of the Persian Gulf includes high petroleum potential, but with structural complexity and this investigation is focused to explore reservoir in its other horizons, specially Sarvak formation as the famous reservoir in the area. To achieve essential information from reservoir and locating it, we applied two useful seismic methods. Authors considered different advantages of the fast Fourier transform (FFT) and the continuous wavelet transform (CWT) as the most commonly applicable spectral analysis of seismic methods in an experimental investigation besides geological new findings. We found that the FFT can provide a good image from reservoir stratigraphic characteristics; it has specifically proven efficient even in carbonate reservoirs allowing individualization of geological bodies not easily defined in amplitude maps. Besides that, the CWT can provide an accurate and clear image from reservoir structural characteristics and low frequency shadows under petroleum reservoirs. We will prove our claims by using theoretical and experimental evidences. Objectives of this paper, beside geological evidences, are to show abilities of these two methods and to describes how, (1) the FFT method shows the distribution of the hidden reef boundaries and (2) the CWT shows the probable presence of hydrocarbons in purpose structure much better than the original seismic data and others methods.

As an important safety discharge facility in petrochemical industry, flare is widely used in offshore and onshore oil and gas fields to relieve pressure, vent unwanted gases. This open-air combustion system oxidizes the fuel gases into carbon dioxide and water vapor and hence avoids the contamination of air with harmful gases that cause air pollution and climate change. With the increasingly strict requirements of environmental protection and the implementation of low-carbon development policy, the black carbon (soot) caused by incomplete combustion from the flare will be strictly controlled. At present, there is no simple and effective method to determine whether the flare produces visible black carbon which exacerbates the pollution. According to the investigation on site, there are different degrees of black carbon emission from the flares both in the onshore and offshore oilfield, which brings some troubles to the petroleum corporation. Based on a flare tip and the associated gas from an oilfield in Bohai Bay of China, a simulation model, which in accordance with the actual situation, was established with the Computational Fluid Dynamics software. The Non-Premixed Combustion model was used to simulate the Combustion, the P-1 model was adopted to calculate the thermal radiation and the Moss-Brookes model was selected to compute the generation of black carbon. The feasibility of the model was demonstrated by comparing the simulation results with the field test results. Then the limitation of current conventional practice to predict whether the soot is produced, was demonstrated with the model. At the same time, the production rate of black carbon under different conditions of components and fraction were calculated. After a comprehensive analysis and comparison, a simple, directly and effective method to predict the soot was proposed. When the C-to-H ratio of fuel gas is greater than 0.273, it tends to visible soot, and when the C-to-H ratio is greater than 0.285, it tends to heavy soot, which is in line with the actual in site. Therefore, the method can be applied to predict the level of the generation of black carbon in the engineering.

The goal of oil and gas field development is to maximize the benefits of exploitation work. In some large oilfields entering the mid-to-late development stage, to maximize the input-output ratio of oilfield exploitation, in oilfield development work, you will receive Due to the influence of many interference factors, in the field of oilfield exploitation, it is necessary to reduce the economic cost of oil and gas field exploitation as much as possible and continuously improve the economic benefits of oilfield mining units. In the mid-to-late production of oil and gas fields, the use of big data to establish a reasonable and scientific production plan for oil fields and an effective decision support system provide an important guarantee for the development and production of oil and gas fields in the middle and late stages. Through the use of effective production-increasing technology and production decision-making, comprehensively consider some oilfield mining areas and newly-added resource mining areas, comprehensively optimize and set up the development of oilfield resources in the middle and late stages and use big data technology to develop oilfields. Among them, the resource advantages are effectively transformed into economic advantages, in order to provide a good work plan for the middle and late stages of oilfield development.

At the end of April 1983, there were 3,088 active oil and/or gas fields in the state of Oklahoma, as well as 32 officially named abandoned fields, according to the Nomenclature Committee of the Mid-Continent Oil and Gas Association. Oil and/or gas fields are located in 73 of Oklahoma's 77 counties, and represent over 4 million acres (1.5 million ha.) in surface area. The Oklahoma Geological Survey has prepared a new, up-to-date map of all officially named oil and/or gas fields in the state, at a scale of 1:500,000. Each field is outlined, assigned an index number for reference, and designated by color code as either an oil field, gas field, or combination oil and gas field. As an improvement over oil and gas field maps available from commercial sources, the OGS has attempted to define better the geographic boundaries of each field. An alphabetical listing of all fields with their reference numbers and locations is featured on the map, along with a listing of smaller fields that have been combined into Oklahoma's major oil and gas trends. The map is designed for use as a reference by all oil and gas professionals in the state. The OGS oil and gas field map has been prepared in conjunction with the development of a computerized oil and gas field file for Oklahoma. Production of updated versions of the map in future years will be facilitated by digitization of information shown on the present map. End_of_Article - Last_Page 459------------

Accumulated oil production from the Troll field offshore Norway will reach one billion barrels of oil in the spring of 2005. At 315-340 meters water depth, Troll is an oil and gas field with approximately 1,700 billions Sm3 of gas and four billion barrels of oil in place. Troll consists of two main structures, Troll East and Troll West, the latter divided into an oil and gas province. The oil is located primarily in Troll West in thin oil layers of 4-27 m. This article describes how the Troll West field has been developed from a gas field with no commercial oil to a gas and oil field with accumulated production surpassing one billion barrels of oil during the spring 2005. Introduction This article describes the multi-disciplinary success story of the Troll West oil and gas field. Originally, the Troll field's thin oil layer of 4-27 m thickness was considered to have no commercial value. The development of horizontal drilling technology combined with early testing and oil production from a floating platform (FPSO) led to the conclusion that Troll West oil could be commercially produced. The most productive part of the field is the Troll West Oil Province (TWOP) with 22–27 m oil thickness. It was first developed by the installation of five subsea clusters and the Troll B FPSO in 1995. Drilling and production performance led to further development of the even thinner oil layers (4–14 m) in the Troll West Gas Province (TWGP), and installation of the separate Troll C platform, which began producing in 1999. The Troll field is one of the largest subsea developments in the world with 107 wells currently in operation. Increased oil recovery from the thin oil layers in Troll West has been possible by gradually increasing the length of the horizontal sections and introducing multi-lateral wells to reduce cost and increase the sweep area. Advanced drilling and completion technology have been developed and implemented. Seismic and geological methods determine the location of the high-permeable sands with high accuracy. The drilling and completion operations have been significantly more efficient, resulting in a higher drainage area per invested capital. Continous production drilling with up to four floating drilling rigs has been carried out since production start in 1995. More than 30 multi-branched wells with zonal control are in operation. Five three-branched, two four-branched and one five-branched well are currently in production. Figure 1. The Troll Field is located some 80 kms west of Bergen, Norway. (available in full paper) The Troll Field The Troll field is located some 80 kilometers west of Bergen, off the coast of western Norway. The water depth is 315-340 m. The Troll field consists of Troll East, mainly covered by production license 085, and Troll West, mainly covered by production license 054, see Fig. 1. The Troll license partners are:ConocoPhillips Norge 1.62374 %Total E&P Norge AS 3.69096 %A/S Norske Shell 8.10145 %Norsk Hydro Produksjon AS 9.77914 %Statoil ASA 20.80471 %Petoro AS (Norwegian state) 56.00000 %

Chapter 3 - Marine Petroleum (Gas) Engineering and Equipment

A number of productive oil and gas fields are located in the Absheron Peninsula of Azerbaijan. The primary goal of the presented study was to quantitatively assess the ground deformation (subsidence and uplift) rates of oil and gas fields, determine natural and man-made influencing factors and predict deformation trends. Persistent Scatterer Interferometric Synthetic Aperture Radar technique was used for the present studies to detect ground deformation rates and velocities in the Absheron oil and gas fields. The existence of ground deformation processes was observed for the period of 2015–2017 with three hotspots of highest subsidence rates and three hotspots of highest uplift rates in oil and gas fields. The determined maximum displacement rates of subsidence and uplift processes were −26 mm/y and +23 mm/y, respectively. However spatial density analysis of deformation velocity presented the natural patterns of uplift and subsidence tectonic processes. This allowed to determine that two oil and gas fields hold a higher probability of being affected by man-made oil and gas exploration activities, whereas the one oil field is affected by both natural and man-made processes. Geographically Weighted Regression analysis revealed that well concentration and elevation factors provided 32% of explanation to subsidence processes.

Major hydrocarbon reserves have been discovered and developed during the last 20 years in the Russian Arctic. Productive basins include the West Siberian, Pechora, and Vilyuy. Gas discoveries in the Anadyr basin are too new to be evaluated. Untested basins include the following: (1) onshore: Anabar, Lena delta, Indigirka, and Kolyma; and (2) offshore: Barents and Pechora Seas, Kara Sea, Laptev Sea, East Siberian Sea, Bering Sea, and Sea of Okhotsk. In the West Siberian basin, as of January 1, 1970, more than 40 oil fields and 50 gas fields had been found. Production is from Cretaceous and Jurassic paralic to nonmarine strata. At least 9 oil fields had reserves greater than 500 million bbl; 20 gas fields had reserves greater than 3.5 Tcf. Samotlor is the largest oil field with 15.1 billion bbl; Urengoy, the world's largest gas field, had 210 Tcf. Deepest production was from about 10,500 ft, but most production was shallower than 8,150 ft. The Pechora basin contained about 62 oil and gas fields productive from Devonian through Permian marine strata. Of these, 1 oil field contained more than 500 million bbl and 2 gas fields, more than 3.5 Tcf. Deepest production was from about 11,155 ft. The Yenesey-Khatanga trough contained several fields, but is relatively undeveloped. The Vilyuy basin contained about 41 gas fields, of which 2 gas fields contained more than 3.5 Tcf each in Triassic and Jurassic paralic strata. Deepest production was from about 9,840 ft. More than 200 structures remain to be tested in the 4 basins. Although deformed basement has been penetrated in several areas, particularly near basin margins, the basin centers have not been explored thoroughly. In most of the West Siberian basin, for example, 2,000-8,000 ft of section below the deepest producing zones has not been tested. In the West Siberian basin alone, proved plus probable oil reserves exceed 35 billion bbl, and proved plus potential gas reserves exceed 400 Tcf. If the results from the West Siberian, Vilyuy, and Pechora basins are indicative of Russian Arctic potential, a bright future could be in store for the Russian petroleum industry. Despite the high costs and enormous logistics problems involved in development of these remote permafrost areas, the Russians are well on their way in developing End_Page 2495------------------------------ the West Siberian fields. The first pipeline of 40-in. diameter was completed to the Omsk refinery in 1967, and a second pipeline, of 48-in. diameter, is under construction. Siberia already has achieved self-sufficiency and the flow of crude oil in the Trans-Siberian pipeline was reversed west of Omsk in the summer of 1970 so that surplus West Siberian crude now moves westward to European Russia instead of the previous eastward flow of Volga-Urals crude to Siberia. In the Pechora basin, development of the largest potential producer, the Usa field, was underway in 1970 and construction of a pipeline to the Yaroslavl refinery in central Russia was started. The gas of the Vilyuy basin at present is used only locally, in the city of Yakutsk. No specific plans for long-distance transmissio have been announced. End_of_Article - Last_Page 2496------------

Water shutoff treatments need different approach and chemicals in gas and oil fields due to the inverse mobility ratio. Therefore, the primary aim of the research project was to develop special treating solution, which may form barrier phase against the flow of water by in-situ mixing of the treating fluid with formation water. As a novelty, water sensitive petroleum-based solutions were developed, which are stable until they are contacted with water. The induced phase inversion of such metastable systems restricts the water flow by 80-90% in sandstone cores through evolving extremely high viscosity in the mixing zones. Optimizing the composition of the treating fluid containing environmentally friendly chemicals the method was qualified as matured for field pilot tests. In 2013 and 2014, five pilot tests (one repeated one) were carried out at the largest Hungarian stacked oil and gas field. All wells were operating in a depleted gas-capped oil field after terminating the oil production from the lower zone. Special treatment protocol tailored individually to wells was used and injecting 40-100 m3 treating solution, nitrogen drive served to reach deep penetration in the reservoir. Applying short shut-in time, transient production period was observed, and that was followed by gradual and unexpected improvement of production characteristics. Depending on wells, the water production dropped by 40-60% in certain wells; meanwhile in other cases the water production slightly changed though, but the gas production doubled and tripled. The most stunning observation was that all wells never producing oil earlier started to produce substantial amount of oil. Until now, the accompanying oil production is more than 2500 t (18,000 bbl). The outstanding performance of well treatments can be attributed to water shutoff, reduced skin factor, bottomhole clean-up and mobilization of the residual oil saturation from the lower zones. The field project is successful not only in technical, but also in economic point of view. Evaluation of all data proved that the multifunctional stimulation technology might open new vistas in reservoir conformance control in gas fields.

This paper propose a LEAN design and LEAN approach for project development of Mobile Production Facility (MPF). The Mobile Production Facility (MPF) is the well known facility developed in onshore oil and gas field for mature field which the field development plan has extended to remote areas which contain small marginal oil prospects. The LEAN design for Mobile Production Facility could improve the economics of onshore oil and gas projects development by reducing capital expenditure (CAPEX) and project development lead times and increasing flexibility for production planning through the mobilization design, and be a key factor in the economic exploitation of both marginal and mature fields. Insight gained through in-house design, international code & standard, and package design experts led to the development of the LEAN Mobile Production Facility proposed in this paper. Discussion include a characteristic of a reference oilfield, project background, application of Mobile Production Facility, the innovative design of package and equipment leading to lower CAPEX in detail, as well as the benefits and limitations of the LEAN Mobile Production Facility. Areas of future project development in support of LEAN Mobile Production Facility are identified, including the potential to unlock the further marginal reserves.

The production of sulfide by sulfate-reducing bacteria (SRB) in oil and gas fields causes problems including enhanced corrosion risk, reservoir plugging and deterioration of product quality. Injection of nitrate or nitrite stimulates heterotrophic nitrate-reducing bacteria (hNRB), which compete with SRB for oil organics, such as volatile fatty acids (VFA). Nitrate also stimulates nitrate-reducing, sulfide-oxidizing bacteria (NR-SOB), which lower sulfide levels. Nitrite is a strong and specific inhibitor of the SRB enzyme responsible for sulfide production, whereas nitrate does not inhibit SRB. Hence, injection of nitrate or nitrite can prevent or remediate problems in the oil and gas industry caused by SRB activity, provided hNRB and NR-SOB are present. A survey of 8 oil fields, 2 gas storage reservoirs and an oil storage tank indicated that SRB and hNRB were widely distributed, whereas the distribution of NR-SOB appeared more limited. The SRB and hNRB were able to use lactate, as well as VFA as electron donor for sulfate or nitrate reduction. However, the order of use of VFA components appeared to differ with acetate being used preferentially by hNRB and propionate and butyrate being used preferentially by SRB. The production of nitrite by hNRB and NR-SOB varied greatly with quantitative conversion of nitrate to nitrite (up to 30 mM) being observed in one case; the nitrite formed was then reduced further. Samples from a high temperature North Sea oil field had thermophilic SRB, but no hNRB or NR-SOB activity, causing sulfide production to be inhibited by nitrite only. Although nitrite appeared to react chemically with sulfide under these conditions, causing all nitrite to disappear within 100 h, the observed inhibition was long-lasting (>500-1500 h). Hence, nitrite can be used successfully to control SRB activity in fields where hNRB and NR-SOB are absent. In summary, it appears that many oil and gas fields contain hNRB and NR-SOB populations, which are activated upon injection of nitrate or nitrite, allowing sulfide remediation in situ. Characterization of these populations as described in this paper may allow prediction whether these injections will be successful and whether use of nitrate or of nitrite is preferred.

One of the real challenges facing the oil industry in Egypt now, is to keep up production and maximize reserves especially in mature oil fields. The application of artificial lift systems to improve the productivity, whilst ensuring the most effective use of the existing reserves, should optimize the petroleum resources. A total of 137 oil and gas fields were placed on production since the oil industry in Egypt started in 1910. Currently there are 122 oil and gas fields on stream, among which 9 are gas production fields and the other remaining 113 are producing oil from 1311 oil wells. The natural producing wells are representing 15%, while the gas lifted wells are 24% and the pumped wells are 61%. This paper presents the philosophy and the methodology of applying artificial lift system in the Egyptian oil fields. Pending on the production forecast and the expected well behavior and also the effects of applying the secondary recovery mechanism either by water flood or gas injection. Also the problems encountered on well behavior are analyzed and solutions are suggested. Special emphasis is given to the marginal oil fields artificial lifting systems, because of the economical limitation accompanied with such field's development costs. The concept is not only to equip a well with a cost effective means of artificial lift to be able to continue production, but also to manage the reservoir behavior for the maximum oil recovery.

Background. Designing problems of oil fields infrastructure in the Arctic under climate change, namely, applying of temperature coefficient when calculating bearing capacity, heaving of lightly loaded foundations, optimization of thermal stabilization solutions are presented in the article. Aim. To change the strategy for designing foundations on permafrost by choosing the worst soil conditions to the implementation of an invariant matrix for designing and construction of soil bases and foundations considering specifics of industrial facilities of oil and gas fields based on unified numerical calculations (regulations). Materials and methods. An overview of the current regulatory requirements to the design of foundations on permafrost is made. The analysis of forecast modeling of the temperature of soil bases of typical industrial facilities of oil and gas fields to justify design solutions and also the use of thermal stabilization systems is done. Results. It is proposed to develop a regional directory of weather stations with long observation period based on updated climate data to decrease the volume of designing work and the amount of mistakes in applying of thermal stabilization systems. It is necessary to create regional dynamic models of permafrost geosystems, implement forecast modeling of seasonal thawing potential depth and frozen ground temperature in natural landscapes on the base of geotechnical monitoring data and select adaptation methods to existing or expecting climate change trends. Conclusions. Regulations on designing and construction of soil bases and foundations on permafrost considering specifics of industrial facilities of oil and gas fields is an effective solution. It allows moving on the strategy implementation of uniform approaches to oil fields development on permafrost: from designing for every structure on the base of typical solutions and results of engineering surveys to invariant matrix of project solutions.

The newly developed methods of geochemical exploration will undoubtedly play an important role in exploration for oil and gas fields. There has been a tendency in this country among the explorers for oil and gas to undervalue the role of surface evidences of such deposits. Most of the great oil fields of the world have been indicated by surface evidences. In view of the prevalence of visible oil and gas seeps it is reasonable to expect to find microscopic seeps in much greater abundance. In practically all cases maximum leakage occurs from the edges of accumulations. These leaking gases are adsorbed by the earth particles near the surface and are then polymerized to the heavier hydrocarbons. The gases in leaking to the surface transport quantities of subsurface waters and the dissolved minerals, resulting in many cases in high mineral concentrations near the surface. The data of geochemistry have led to some very interesting speculations regarding the genesis of oil and gas fields. Evidence strongly suggests that oil and gas fields result from the polymerization of the migrating hydrocarbon gases. Two sources of such gases have been measured, namely, vegetable matter that is being devolatilized and the basement rocks. There may of course be others as yet unmeasured. The important consideration is that so far as migration is concerned the gases are the principal participants. It is believed that the oil accumulations and the concentrations of adsorbed hydrocarbons in the soil and in the oil shales are genetically related. As the principal difference between marine and non-marine sediments is the presence of sodium chloride (not organic content according to Trask), and as this will act as a catalytic agent to polymerize the hydrocarbon gases, it is reasonable to suppose that this is why oil fields occur in marine rather than non-marine sediments. Experimental laboratory investigation verifies this. If one goes back far enough in point of origin of the organic gases either in the buried vegetable matter or the basement rocks both origins would immediately become inorganic. In view of this can it be said that there has ever been an organic theory of the origin of oil and gas? On the basis of the hypothesis proposed it is possible to explain the difference in mineralization of subsurface waters in different geologic provinces, as well as the relation between volatility of accumulations as a function of the carbon ratio (rock deformation) and overburden. Caliche may owe its existence to the transporting power of the vertically migrating gases. It should be kept in mind the method of geochemical exploration is not predicated on the theoretical conceptions here presented. Rather, the reverse is true, in that the theory is derived from the data of geochemistry.

The efficient development of low permeability reservoir exploration and development at home and abroad has been a difficult and hot issues. Changqing Oilfield is the permeability, low pressure, low abundance of the "three low" oil and gas fields, is the world famous low permeability. In recent years, with the low permeability of Changqing Oilfield fast on the scale of production, development and gradually increase the difficulty, well production decreased year by year, oil layers, layer contradictions become increasingly prominent. Changqing Oilfield how old stable production, it will be a challenging task. In this paper, Changqing Oilfield per 214 Jiyuan Chang 4 +5 reservoir, for example, focuses on the reservoir of the reservoir by strengthening fine management and implement water policies, improve water technical control, good water injection, inject enough water, improve the capacity of the reservoir stable production, improve development effectiveness.