Concurrently in the West of Venezuela, they have come proposing technicians to improve the recovery of oil weighed through of new processes of thermal stimulation that do not use water steam as agent of heating.
In this work it is considered the injection of hot gasoil the reservoir and exists the thermal stimulation process´s physical mathematical foundation, based on the several mechanisms of heat transference as convection and conduction, as a whole with the mechanism of transference of matter for liquid diffusion - liquid, which one, it based in: A Balance of calorific energy, through it is determinated distribution of temperature in the reservoir, and the heat losses to the adjacent formations evaluated by the model of Marx and Langengein, besides the model of production defined by Boberg and Lantz. A Balance of matter ruled by Fick's Law of the diffusion oil -solvent , and the equation of difusitivity that governs the transitory behavior of pressure defined by Everdingen and Hurst.
The stability of the simultaneous solution of the differential equations system is acceptable, due the founded solutions are analytical type.
Operationally the efficiency of the stimulation and the field practice, they will be key points that there will allow the successful execution of the planned process, through the wells completation with sand control filters, sensors of pressure and temperature, besides the thermal equipments of completation that requiere the thermal processes.
To illustrate the field application of the proposed technology, there was selected the reservoir Bachaquero-01.
The results obtained in several running of sensibilities, indicate that it is achieved an increase obtains in the mobility factor of the oil at reservoir conditions of 10,5 times superior than the original one. Giving cycles of production of approximately 10 months, for a stimulated average rate with hot solvent of 850 BN/day versus stimulated average day with steam of 380 BN/day, in an arrangement of conformated wells by two horizontal ones in parallel.
The obtained results indicate that the heat solvent injecting technology to the formation is more favorable alternative than the steam alternate injection process, due it is predicted a major optimized recovery of oil by cycle.
The use of hydrocarbons solvent liquid, as the naphtha, kerosene, gasoil, they have been used to improve the process of the recovery of oil for steam injection, and to been reported and studied in a lot of works, even several processes have been patented depending on the type of solvent used, specifically in the injection of vapor/solvent. Allen (1976), proposed the use of a pot-hole of mixture composed by an aromatic hydrocarbon as solvent and a gaseous component as dioxide of carbon, to establish a preferential way between the well injector and the producer well , after which the oil is moved for constant injection of warm water or steam. Best (1979), Otherwise, he present a improved stimulation with steam in which one the oil in the formation is submitted to one o more steam cycles, followed of a pot-hole of mixture of a hydrocarbon solvent before the following cycle of steam injection.
Later, Buckley and Grist (1980) propose the injection of a pot-hole of mixture of a distilled solvent, as tolueno or refined oil mixed with an oil sulfonato surfactante, in order to increase the permeability to the water in the reservoir before the injection of the steam. In this case, the proposed solvents and the schemes might be used in the cycles of steam injection, as well as in any process of thermal stimulation with steam.
Islip y Shu (1984) present an invention that consists in the injection of a given quantity of a steam and solvent with the producer closed well. The injector well is then closed and the producer well is opened to extract the fluids from the formation, these stages are repeated cyclically in the time.
Dou, Hong'en (RIPED,PetroChina) | Chang, Yu Wen (Research Inst. Petr. Expl/Dev) | Yu, Jun (Liaohe Oilfield E&D Research Inst.) | Wang, Xiaolin (RIPED,PetroChina) | Chen, Changchun (China U. of Petroleum) | Ma, Yingwei
This paper presents a new mathematic model to calculate heated reservoir area based on the heat balance principle in order to determine the well spacing for thermal recovery. The calculation result of the new model was compared with the classical models of J.W Marx and R. H. Langenheim (Petroleum Transactions, AIME Vol. 216, pp. 312-315, 1959), B. T Willman (JPT, July 1961, pp. 681-696), and Farouq. Ali (1970), using data from Liaohe heavy crude oilfield, China. The results showed that the new model is more accordable with oilfield actual condition than the three classical models. Also, this research reveals a new theory on huff ‘n' puff, which is that the heated radius of the heated region is expanded from the first cycle to the fourth cycle of huff ‘n' puff; in this case, the heated front was expanded with the increase of cycle. However, subsequent cycles (from fifth cycle to tenth cycle of huff ‘n' puff) repeat the heating of the previous heated areas, and the expanding heated area of the next cycle is smaller than the last cycle, and the new heating region should hardly be expanded after the 10th cycle. The authors point out the development results of heavy oil, extra heavy oil and super heavy oil deteriorate due to this reason. In addition, the authors emphasize that the traditional huff ‘n' puff for producing heavy oil, especially for extra-heavy oil and super-heavy oil has to be changed using new technique methods after the fourth cycle. Finally, a suitable well spacing for thermal recovery with huff ‘n' puff was obtained. The new theory was proved by heavy crude/extra heavy oilfield development.
Huff ‘n' puff has been used in heavy oil reservoir development since the 1960's. Heavy oil production techniques have been advanced greatly in Canada and Venezuela. In the early 1980s, many thermal recovery techniques were developed, such as insulation tubing, high temperature packer and measurement instrument of thermal parameters. In Liaohe oilfield, China; the reservoirs are at depth from 800 to 2000 m. Heavy oil development was a great success, with production rate reached 700×104 tons per year. During the 25-year production period (1980 to 2005), 20 % of the oil in place was produced. The mechanism of production was a combination of solution gas expansion and huff ‘n' puff, as the cycle of huff ‘n' puff is more and more, the development result become worse and worse. Currently, huff 'n ‘puff has exceeded 15 cycles in some wells. The adjustment of oil development strategy faces great challenges, especially in planning well spacing for different types of reservoirs in the oilfield to reach the maximum thermal recovery. The heating front of steam injection, swept region of hot water and the determination of the heated radius are the main parameters to be taken account for designing the well spacing of the heavy oil reservoirs during huff ‘n' puff. Well spacing for thermal recovery will not be determined if the heated radius should not be calculated accurately. Therefore, after the three classical models of J. W. Marx-R. H. Langenheim (1959), B. T Willman (1961) and Farouq. Ali (1970) was analyzed [1-3], and the paper presents three generalization calculation equations and a new model for calculating the heated radius of the thermal recovery.
Analysis of Classical Model
Many researches have developed the theory for the estimation of the heated radius of the heated region and design of well pattern by some scholars [4-8], and the three classical models of Marx-Langenheim (1959), Willman (1961) and Farouq Ali (1970) were used and introduced widely. However, the three models were not analyzed systematically, and the conclusions and recognizing of the heated radius of actual oilfield were not presented in past published papers. Also, the heated radius calculation of multi-cycle had not been revolved. Three generalization mathematics models of the heated radius with multi-cycle were given on the basis of the three classical models. Different performance characteristics of heavy oil, extra heavy oil and super heavy oil are analyzed by means of the three generalized mathematical models and actual oil field data.
Nares, Hector Ruben (Inst. Mexicano del Petroleo) | Schachat, Persi (Instituto Mexicano del Petroleo) | Ramirez-Garnica, Marco Antonio (Inst. Mexicano del Petroleo) | Cabrera, Maria (Instituto Mexicano del Petroleo) | Noe-Valencia, Luz (Universidad La Salle)
In this paper are discussed the effects of some metallic oxides used to upgrade the heavy crude oil properties. The underlying objective is to increase the mobility of the oil in the reservoir by reducing viscosity and improving the oil quality using alumina supported transition metals and liquid phase transition metals catalysts (derived from either acetylacetonate or alkylhexanoate compounds), both homogeneously mixed with heavy crude oil. This heavy crude oil upgrading is based on the decrement of the asphaltenes, resins, and sulfur contents, and the increment of its API gravity, and strong reduction of viscosity.
In the present work the heavy crude oil from the Golf of Mexico was studied. The API gravity was increased from 12.5 to 21-26, the kinematics viscosity was decreased from 18,130 to 100-8 cSt (at 298 K), the asphaltene content was reduced from 26 to 7 wt%, the sulfur was removed in the range of 30 to 60 wt%, and the distillable fraction was increased between 20 to 30 wt%, and determinated by Simulated Distillation and True Boiling Point (TBP).
Heavy crude oil can be an enormous energy source when the suitable technology is used to its improvement in both cases aboveground and within reservoir. The extremely large reserves of the heavy, extra-heavy crude oil and bitumenes (5.6 trillions barrels) and the low cost are the main factors that make attractive as feedstock in the refining industry [1, 2]. On the other hand, the word-wide of the conventional crude oil reserves have been drastically diminished to 1.02 trillions barrels causing in some countries (México) that a great percentage of heavy crude oil (50 vol.%) is mixed with conventional crude oil and is used as feedstock to the atmospheric distillation [1, 2]. Although in the past, the easy processing of the conventional crude oil favored the production of distillates, currently the situation is changing quickly and it could be different in a short term because of the high demand of fuels oil that is why it will be necessary to process heavy and extra heavy crude oil.
Nowdays, some of the main problems that heavy crude oil presents are as follow: (1) the low mobility through the reservoir as a consequence of its high viscosity, which affects the wells productivity index, (2) the difficult transportation to the refineries and its high costs, and (3) the low processing capacity in the refineries. For these reasons is fundamental to enhance the heavy crude oil, both aboveground and underground. Talking about aboveground oil upgrading, several processes have been studied and applied in the industry to improve the bottom barrel conversion. Some of the main processes are carbon rejection (Thermal Processing, Delayed coking, Fluid coking, Flexicoking, and Visbreaking) [3-5]; hydrogen addition (Hydroprocessing, Fixed-bed as Hyvahl-F, Ebullating Bed as H-Oil and LC-Fining, and Slurry Phase) [6-9], and physical separation (Extractive Processes, FW Solvent Deasphalting, and Demex) [10-12]. All these processes are focused on converting the atmospheric and vacuum oil residues (511 K+) into more valuable products such as gasoline, middle distillates and Fluid Cracking Catalytic (FCC) feedstock. Nevertheless, the hydroconversion of heavy crude oil aboveground has been applied only at semi-industrial level because of: (1) the special design of either fractionation towers or topping columns, (2) the high investment due to great hydroprocessing volumes of heavy crude oil required in the refineries, and finally (3) the high hydrogen and catalysts consumption.
An interesting alternative to recover the heavy and extra-heavy crude oil is the down-hole catalytic upgrading. This alternative presents several advantages comparing with its aboveground counterpart such as: (1) an increase in the well productivity index, (2) a reduction in the lifting and transportation costs from the downstream to the refining center, (3) the production of more valuable products as a consequence of the decrement in viscosity values and in the resins, asphaltenes, sulfur, and metal contents, and (4) the application of environmentally accepted processes.
The present work addresses the contributions, in both individual and combined forms, of the driving mechanisms, namely, solution gas, CO2 generation, steam distillation, capillary imbibition and gravitational drainage, for the recovery of oil and gas during the continuous steamflooding of a naturally fractured reservoir containing heavy oil. The investigation is carried out via numerical simulation of the phenomena in representative pattern cells.
Two numerical models were used to represent the matrix heating process. The first describes the heating of a horizontal
cross-section of a matrix block surrounded by a fracture, in which the steam is steadily flooding. The second model is
similar to the first, except for the position, which is changed to vertical to incorporate gravity effects. The studies were performed for a fractured rock saturated with live oil. The rock properties are representative of a real fractured carbonate reservoir, as well as the fluid properties referring to the same field case. Also, the operational conditions used for pressure and temperature were the ones observed in the field, conferring to the work and conclusions, the character of a case study. A strategy was adopted to isolate the effects of each recovery mechanism.
The results show that the main mechanisms of oil recovery for the matrix block during steamflooding are the integrated
action of steam distillation and solution gas. The first is the dominant mechanism and it is responsible for the quality
improvement of the produced oil. The other mechanisms have a minor contribution to ultimate oil recovery. Such results are vital for the design of a steam injection project in similar oil fields.
Before the 80`s, it was believed that steamflooding of a naturally fractured reservoir (NFR) could deviate the oil through the fractures. Consequently, the oil would not be recovered. However, the results of simulation runs and field tests, published in literature since the beginning of the eighties, have shown the economic potential of the use of steam for the recovery of heavy oil in NFR. For the better understanding of the physics involved so as to realize the proper capabilities of the method, it is extremely important to study the main recovery mechanisms such as: reduction of
viscosity; thermal expansion; distillation; capillary imbibition; solution gas; generation of CO2; and gravitational drainage; as pointed out in Reis' work1 in 1990.
Research efforts on the recovery mechanisms of heavy oil in NFRs during continuous steamflooding are relatively recent, although the basic principles on which the process is based has been under scrutiny since 1961. That year, steamflooding cores, Wilman and co-workers2 demonstrated the existence of the mechanisms of viscosity reduction;
thermal expansion; and distillation. In 1962, Mattax and Kyte3 developed capillary imbibition studies in small cores from
water wetting reservoirs and they showed that the water inside the fracture can be absorbed spontaneously by the matrix, through small pores. In 1969, for a continuous steam injection field project, DeHann and Van Lookeren4 reported the action of the gas solution mechanism, which occurs because of the release of the gas dissolved in the oil due to the temperature increase. In 1970, Kyte5 reported, after a numerical simulation study, that gravitational drainage is as important a mechanism as capillary imbibition. In 1982, Sahuquet and Ferrier6 observed the generation of CO2 during a field test of a fractured carbonate reservoir.
After the 80`s several papers were published on these recovery mechanisms, coming from field project results, laboratory and numerical modeling studies. In 1986, Dreher7 et al. studied the injection of hot water and steam in live oil saturated carbonate rocks. CO2 generation, oil expansion and viscosity reduction were the active recovery mechanisms.
Castanhal is an onshore heavy oil field located in Sergipe-Alagoas basin northest of Brazil. It is a shallow unconsolidated sandstone reservoir. It has 75 wells where the average reservoir depth is 350m. The oil has high viscosity ranging from 1000 cp to 9000 cp and API gravity ranging from 10° to 16° API.
In early eighties, a small steam injection project was started in the field, but due to operational problems it was interrupted few years later. In that time the oil low prices make the field be practically abandoned: The production was carried on by very few wells without any fluid injection. In 2003, some successful experiences with frac pack and horizontal wells lead to a renewed interest in the field.
Geological and numerical studies have been accomplished and a permanent temperature monitoring technology was selected to improve the reservoir knowledge and validate the studies.
Among the monitoring technologies available in the market DTS (Distributed Temperature Sensing) was selected. It
allows a complete wellbore-temperature profile in few minutes if needed. In this case four observetion wells were equipped with an optical fiber placed along the entire length of the well.
This paper will present a steamflooding pilot in a nine spot, with four temperature observation wells completed with frac
pack to avoid sand production and DTS to improve the understanding of steam breakthrough in the producer wells
and the steam path in the injection well. The information support better decision making to increase steam injection
Castanhal field was discovered in June/1967 by 1-CL-1-SE well. It is located in Brazil and lies on north of the Sergipe-Alagoas basin and It is 50km far from Aracaju city (Figure 1). Its reservoirs are fine-grained sandstones and conglomerates from the Carmopolis Member of the Muribeca Formation, with high permo-porosity, saturated with biodegradeable oil, high viscosity ranging from 1,000 to 9,000 cp and API gravity ranging from 10o API to16oAPI. The oil in place (OIP) is about 178x106 bbl (december/2006).
Figure 1: Castanhal field map location.
The field produced oil by cyclic steam stimulation (CSS) and steamflooding during 1990 year and due to lower Brent prices and high operational costs related to sand face control the steam injection project was abandoned2. In 2001 this situation changed by a well succeded frac pack project with equipaments suited for steam injection. A new steamflooding project in a nine spot was started in june/2006 but now adding distributed temperature monitoring in four observation wells.
The geological interpretation of the well logs in about 73 wells drilled allowed, with confidence, to map four pay zones
MUR/CPS-1, 2, 3 e 4. The Figure 2 shows a well log from Castanhal field with its four zones.
Operationally Castanhal field is divided in four sandstone zones, CPS-1, CPS-2, CPS-3 and CPS-4 with different
geological characteristics. Zone CPS-2 has the best lateral continuity followed by zones CPS-3, CPS-1 and CPS-4, where this last one is more affected by the presence of shales.
This paper discusses the recent patent application filed by EnCana Corporation on the use of air injection to improve the performance of steam assisted gravity drainage (SAGD).
EnCana's SAGD/Air Injection process employs standard SAGD well-pair infrastructure. It optimizes between the ability of steam to preheat the reservoir during SAGD and the superior (follow-up) oil displacement efficiency of in-situ combustion.
Operationally, air injection is initiated after thermal communication has been established between well-pairs with steam. One interesting feature of this operating strategy is that down-hole bulk separation of oil and gas occurs which facilitates (a) efficient monitoring and control of the combustion, (b) design of surface facilities, and (c) corrosion mitigation.
Laboratory combustion tube tests are presented that confirm the ability to initiate and sustain combustion, as well as mobilize residual oil saturation to steam, within a SAGD chamber. These experiments were initialized at oil saturations and conditions representative of those in a steam chamber. The residual oil saturations were determined from a full-hole core taken in the vicinity of a mature SAGD well-pair at Foster Creek.
Numerical simulations of post-SAGD air injection are presented that suggest the ability to displace and produce oil banks between well-pairs and that recovery factor can be increased up to 8% of the original oil-in-place over conventional SAGD.
The simulations show oil production rates and recovery factor are expected to increase with higher air injection rates. However, instantaneous air-oil ratios, which are indicative of operating costs, also increase. Thus there is an optimum continuous air injection rate that maximizes profitability. Simulations further indicate that it is possible to recycle flue gases in the injection stream without affecting oil recovery.