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Results
Abstract El Furrial reservoir is an important part of the new giant oil field recently part of the new giant oil field recently discovered north of the Eastern Venezuela basin. Its medium gravity oil is processed at the large gas separation processed at the large gas separation plant of Jusepin. Serious problems have plant of Jusepin. Serious problems have occurred concerning the foam control and asphaltene depositions at the separators and oil gas lines due to the crude oil carry-over containing abundant unstable asphaltenes. This paper presents laboratory and field studies performed in order to evaluate the best commercial foam inhibitors as well as their optimum dosage to control such problems. Laboratory results concluded that most of the commercial anti-foam agents are similar as inhibitors. Although there are certain differences concerning the knockdown-effect. Its optimum dosage was found to be between 0.1 and 1 ppm related to the total processed crude. A clear relation between the - crude oil asphaltene content and the foam stability has been established. The best products were evaluated in the field and the results match quite well those obtained in the laboratory. The use of the best conventional chemical agents reduced deposition, oil carry-over and increased the separator capacity. Further research is in progress to eliminate the oil carry-over to the gas lines and to avoid asphaltene deposition at the subsurface once the reservoir pressure reaches the critical deposition pressure reaches the critical deposition point. point. Introduction Stable oil foam can cause problems in operation equipment. Foams are dispersion systems containing gas as the dispersed phase. Pure liquids rarely foam when degassed. Foreign compounds, such as asphaltenes, must be added to produce a stable gas-liquid dispersion. produce a stable gas-liquid dispersion. These compounds are usually surface active agents that reduce the surface tension of the liquid which prevents the coalescence of gas bubbles prevents the coalescence of gas bubbles dispersed in the liquid. Migration of surfactant molecules along the liquid film from a low to a high surface tension region restores equilibrium and carries thick layers of underlying liquid. This restores film thickness and results in a stable foam. Other factors such as the surface shear viscosity and the viscosity of the foaming liquid may also effect foam stability. On the other hand, crude oil foam decreases in stability as its moisture content increases. Gas-treating solution foaming is one of the most persistent and troublesome problems encountered in the processing of problems encountered in the processing of natural gas. It has contributed significantly to operating costs and reduced operating rates. Foaming can be efficiently and economically eliminated or controlled. Experience indicates that excessively oversized separators will not prevent foam carry over. A defoaming prevent foam carry over. A defoaming agent might be regarded as a surface active agent that increases the surface tension of the liquid. P. 281
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
SPE Member Abstract The Eocene C reservoir of the Ceuta field, in Western Venezuela is prone to produce sand, for this reason the totality of the wells have to produce upon chockes at rates below optimum level. In an attempt to identify why sand production occurs, a systematic study of the production occurs, a systematic study of the reservoir rock was carried out by integration of various core analysis data. The regional system of facies was determined and these facies were selectively tested on triaxial celds for stress determination. Log-derived rock mechanical properties were also used to calculate critical flow rates at which the different facies will collapse, and consequently be produced. produced Introduction The Ceuta field is located at the south eastern corner of the Maracaibo Lake in western Venezuela (figure 1) Since there exist strong differences between production behavior geological characteristics, and fluid distribution the field is sub-divided in 8 areas (figure 2) Area-2 has most prospectivity in the C-3 sand of the Eocene C reservoir (see Table 1 for generalized stratigraphy), and it is in there were the majority of the completed wells produce at controlled rate to avoid sand production. To identify the causes of fines migration and sand production problems in the C-3 sand of Area-2, a methodology was conceived in which a synergism among Geological description, petrophycics production behavior, reservoir petrophycics production behavior, reservoir engineering and Geo-mechanics will lead to the solution or recognition of the acting phenomena in order to optimize completion desiring to produce sand free, without recurring to some produce sand free, without recurring to some kind of mechanical/chemical sand exclusion method. METHODOLOGY DESCRIPTION Geologists provide the starting point for evaluation characterizing the system of facies present in the area, according to texture, morphology grains geometry, distribution, sedimentary structure, and reservoir quality. Those pieces of information are generated from petrographic thin section Analysis, Scanning Electron Microscopy an X-ray diffraction for Formation Mineralogy. Once the primary information, or basic core data, is classified, a selection of core plugs is made to carry-out triaxial tests to plugs is made to carry-out triaxial tests to determine the elastic properties of the rock such as Young modulus, Poisson's ratio, compressive strength and construct Morh circles to determine angle of friction and radial/ tangential stresses. These values will be used to calibrate the log-derived rock mechanical properties which uses the digital sonic log properties which uses the digital sonic log transient time to infer the elastic characteristic of the rock. P. 275
ABSTRACT The pipeline transportation of petroleum fluids can be significantly affected by flocculation, deposition, and plugging of asphaltene, paraffin/wax, and/or diamondoid in the transfer pipelines, tubulars, pumps, and other equipment. The economic implications of the problem of heavy organic depositions in such processes are tremendous. In this report Mexico's experience with the pipeline plugging due to heavy organic deposition is reviewed and analysed based on the present state of knowledge. The modeling basis of a comprehensive estimation and prediction technique is presented. This technique is based on observed field and laboratory data, statistical mechanical theories, polydisperse polymer solution theory, continuous thermodynamics, electrokinetics and transport phenomena, colloidal solution theory, and the FRACTAL aggregation theory. INTRODUCTION A number of problems could arise during the production of petroleum which would drastically increase the production costs. Among these, wax deposition due to a drop in temperature, and asphaltene deposition due to a variety of causes, in the production tubing strings are the prominent problems [l–4]. Therefore, it is of great importance to understand the behavior of heavy organics under various operating conditions. An ultimate goal is to predict whether organic deposition will take place, and to be able to avoid getting to the onset of organic deposition region. Surveys of field experiences [5–7] indicate that asphaltene deposition problem is one of the major factors that increases the production cost. Thus, being able to prevent such deposition, costs could be lowered appreciably. Mexican oil production and its heavy organic deposition problem was selected for this study because of the availability of an abundance of field and laboratory data about it. Laboratory analysis performed on asphaltenes extracted from samples of the crude oils prone to asphaltene deposition, and from the heavy organic deposits revealed that "Mexican" asphaltenes are very similar (in elemental analysis) to asphaltenes extracted from other sources, as can be seen from Table 1. The difference would reside in the asphaltene-particle structure and charge which in the case of Mexican crude oils is negative [6,7]. The molecular nature and structure of the asphaltene fraction of crude oils has been the subject of numerous investigations. There are still serious shortcomings in consistency between such studies because of the varied assumptions that have to be made in deriving the molecular formulae.
- North America > United States (1.00)
- North America > Mexico (1.00)
- Africa > Middle East > Algeria (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Oued Mya Basin > Hassi Messaoud Field (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Berkine Basin (Trias/Ghadames Basin) > Hassi Messaoud Field (0.99)
- North America > Mexico > Tabasco > Bellota-Jujo > Sureste Basin > Salina Basin > Jujo Tecominoacan Field (0.95)
- Well Completion (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract Camorim field lies on the Continental Shelf of Sergipe Basin, under 12-21 mwater depth. Its oil production started in July, 1976 with 300 m3/day; production started in July, 1976 with 300 m3/day; in 1978 it reached 800 m3/dayand slowly decreased to 400 m3/day in 1982. In order to identify causes for the decreasing oil production, a study involving twenty-three wells production, a study involving twenty-three wells was carried on. The produced oils were characterized according to their properties and composition. The oils are of paraffinic and intermediate base and their gravities range from 39 to 17 API, being all crudes extremely rich in the gasoline fraction. Asphaltene contents vary greatly from 0.13 to 11.6% by weight. Gas chromatographic fingerprints, the asphaltene contents, interfacial tension and polarity determinations identified asphaltene deposition as the main cause for the low production rates. The analyses showed that the production rates. The analyses showed that the heavier and high asphaltenic crudes were highly unstable because the intermediate fractions which should stabilize the oil were present at low contents. Furthermore, polarity determinations showed direct correlation to asphaltene contents for several oils. This result led to the conclusion that the other oil polar components, the resins, which serve as peptizing agents for asphaltenes did not contribute to the polarity effects. This fact increases the instability of the oils and provides additional favorable conditions for asphaltene precipitation. precipitation. The case of three wells which undergone several stimulation treatments is described and confirmed the asphaltene deposition. Introduction Camorim oilfield is located on the Sergipe-Alagoas Basin, approximately 6 Kmoffshore under water depths from 12 to 21 m, being one of the largest fields offshore Northeastern Brazil. The field presents seven main production horizons (CPS-1, CPS-2, CPS-3, CPS-4, CPS-5, CPS-6 and CPS-6A) from the Ibura and Carmopolis Member of Muribeca Formation of Low Cretaceous age. The reservoir average depth is 1,900m (pressure of 210 kg/cm2 and temperature of 111.7deg.C) and the Ibura Member has a gross interval of 60 m with a net pay zone of 5 m, while the Carmopolis member is 150 m thick with a pay zone of 60 m. the litology varies from fine sandstone to coarse cengromerates. Oil production commenced in' 1976 with 300 m3/day of a crude, and a GOR of 90-100 m3/m3. In 1978 the production reached 800 m3/day and slowly decreased to 400 m3/day in 1982. In 1985, oil typical characteristics were 31.50 API, pourpoint of 18deg.C, viscosity of 20.1 cSt (37.8deg.C), polarity of 331.5 and 2.6%by weight of asphaltenes. Several stimulation treatments were performed in order to increase production rates performed in order to increase production rates and, presently, the field is producing 900 m3/day with GOR of 200-1,500 m3/m3 below saturation point.
- South America > Brazil > Sergipe > South Atlantic Ocean (1.00)
- South America > Brazil > Alagoas > South Atlantic Ocean (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.71)
- South America > Brazil > Alagoas > South Atlantic Ocean > South Atlantic Ocean > Sergipe-Alagoas Basin > Camorim Field (0.99)
- South America > Brazil > Alagoas > Sergipe > South Atlantic Ocean > Sergipe-Alagoas Basin > Camorim Field (0.99)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract A new method to predict incipient gas hydrate formation in systems containing an aqueous phase in the absence or presence of inhibitors is proposed. proposed. The method which is based on the statistical termodynamic model of van der Waais and Platteeuw for clathrates is implemented in a computational codes Results of several simulations are analysed and compared with experimental data from 67 systems of the literature and Petrobras fields, obtaining good agreement between calculated and observed dissociation pressures, chiefly in multicomponent hydrocarbon systems. pressures, chiefly in multicomponent hydrocarbon systems. Owing to its good performance, the method can be applied as a robust tool in process design or in field operations in which gas hydrate equilibrium calculations are necessary. Introduction Gas hydrates (or simply hydrates) are ice-like crystalline compounds that form when water and gas come into contact, normally at low temperatures and high pressures. Hydrates belong to a peculiar group of substances known as clathrates, which are compound containing two or more components joined hot by an ordinary chemical bond but by the complete enclosure of one type of molecule inside a suitable structure formed by another molecule. Since the discovery of the first hydrate, studies on these compounds have been purely academic and thus restricted to the scientific community. With the development of the US petroleum industry starting in the thirties, the study of hydrate formation gained momentum, particularly when Hammerschimidt proved that the pipeline clogging problems typically encountered during winter months were cased by the formation of hydrates rather than of ice, as had been thought previously. Innumerous researchers soon began studying this phenomenon and produced a number of predictive methods based on theories ranging from simple empirical predictive methods based on theories ranging from simple empirical correlations to the detailed microscopic study of intermolecular forces. Due to Brazil's climate, specifically to its high temperatures, hydrate formation in petroleum facilities had never presented a serious problem. However, with the steady advance of production activities into problem. However, with the steady advance of production activities into deeper and deeper waters, the possibility of low seafloor temperatures causing hydrates to form inside pipelines has increased substantially. Although the literature presents a number of predictive methods, at the time that these were proposed they were only compared against experimental data on simple gas systems. Their application to more complex gas systems, such as natural gas, may lead to serious errors. The purpose of this study was to optimize process design and operational procedure concerned with the formation of natural gas hydrates, by providing reliable predictions of the conditions under which the phenomenon will occur and which include the presence of inhibitors. A new predictive method based on van der Waais and Platteeuw's theory is proposed and implemented in FORTRAN ANSI 77 computational code. The proposed and implemented in FORTRAN ANSI 77 computational code. The results of several simulations are analyzed and compared with the experimental data on multicomponent mixtures available in the literature or obtained in Brazilian oil fields. SOME ASPECTS OF THE CRYSTALLINE STRUCTURE OF HYDRATES Hydrates crystallize into two types of structure, known as I and II.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Reservoir Description and Dynamics > Non-Traditional Resources > Gas hydrates (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)
Abstract Despite prolonged water injection and a number of reservoir studies, only 10% of the original oil in place has been recovered during 43 years of production from shallow reservoirs in the Dom Joao oil field, Reconcavo Basin. The formation temperature being close to the pour point of the crude oil raises the possibility point of the crude oil raises the possibility for the ocurrence of paraffin precipitation in the reservoir. A field stimulation test was performed using a nitrogen generation performed using a nitrogen generation system/emulsion (SGN/EMULSAO) technique. Two nitrogenated salt solutions, emulsified in a selected organic solvent, were injected into the formation through a single well; their reaction released both nitrogen and heat, in turn yielding a capacity to remove paraffin deposits. A comparison between the production rates and oil compositions before and after stimulation indicates that paraffin deposition was occurring inside the formation. A possible explanation for this phenomenon would be the cooling effect resulting from a post-migration uplifting of the formation. Introduction It is always difficult to ascertain just what is going on inside a Petroleum reservoir. When paraffin precipitation problems affect production tubing, surface equipment, or production tubing, surface equipment, or flowlines, they are easily detected but when they occur inside porous media, investigation becomes more difficult. In fact, only recently have petroleum engineers recognized this problem, which can seriously impair well problem, which can seriously impair well productivity. productivity. In one of Brazil's largest petroleum fields, the Don Joao, it can nevertheless be reliably demonstrated that heavier petroleum fractions are retained inside the reservoir. Indications of this situation were identified in laboratory data and later proven in a field test. A well that was stimulated through heat and solvent injection began producing heavier petroleum at much higher flow rates, as petroleum at much higher flow rates, as indicated by chromatographic data arid studies of average molecular weight. The nitrogen generation system/emulsion (SGN/EMULSAO) method was used to stimulate the well. This important new technological tool involves the simultaneous injection of two nitrogenated salt solutions, emulsified in an organic solvent. The reaction of the two releases nitrogen and heat, in turn yielding a capacity to remove paraffin deposits. Ascertaining what goes on inside a reservoir is not merely an academic question. In the case of the Don Joao Field, the diagnosis that was obtained opens the way for improving production from a field where exploitation has historically beet difficult. In this particular case, the accurate identification of the problem is especially important because there are indications that it may not be limited to the wellbore area and still other indications that it nay be occurring in other shallow reservoirs of the same basin. PARAFFIN PRECIPITATION PARAFFIN PRECIPITATION Paraffin deposits consist essentially of linear and branched-chain hydrocarbons with eighteen or more carbon atoms. These components are normally in equilibrium in the liquid petroleum fraction. When variations in pressure petroleum fraction. When variations in pressure and temperature occur, however, this equilibrium may be disturbed. causing paraffin to precipitate and form deposits that usually contain other organic and inorganic materials as well. In characterizing paraffinic oils, the properties of greatest interest are paraffin properties of greatest interest are paraffin content, pour point, and cloud point. Paraffin contents of over 10% may be suggestive of a significant precipitation potential. Precipitation begins when the temperature drops Precipitation begins when the temperature drops below the cloud point, modifying the rheological properties of crude oils and causing turbidity in translucid oils.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Brazil > Bahia > Reconcavo Basin > Dom Joao Field > Sergi-Água Grande Formation (0.99)
- South America > Brazil > Bahia > Reconcavo Basin > Dom Joao Field > Sergei Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Rub' al Khali Basin > Bu Hasa Field > Thamama Group > Shuaiba Formation (0.99)