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Collaborating Authors
Results
Detection of the Onset of Asphaltene Precipitation in a Heavy Oil-Solvent System
Luo, P. (Petroleum Technology Research Centre (PTRC), University of Regina) | Kladkaew, N. (Petroleum Technology Research Centre (PTRC), University of Regina) | Gu, Y. (Petroleum Technology Research Centre (PTRC), University of Regina) | Saiwan, C. (Chulalongkorn University)
Abstract When a hydrocarbon solvent is made in contact with a heavy oil under a sufficiently high reservoir pressure, asphaltene precipitation occurs so that the heavy oil is in-situ upgraded during a solvent-based heavy oil recovery process. Some physicochemical properties of this in-situ upgraded heavy oil are rather different from those of the original crude oil in the heavy oil reservoir. In this paper, a series of saturation tests is conducted for a heavy oil-propane system under different saturation pressures in a see-through windowed high-pressure saturation cell with six sampling ports at different vertical locations. The onset of asphaltene precipitation is determined by measuring and comparing several physicochemical properties (e.g., the solubility, oil-swelling factor, density, viscosity, and asphaltene content) of the propane-saturated and flashed-off heavy oils taken from different parts of the propanesaturated heavy oil under each saturation pressure. It is found that when the heavy oil is saturated with propane at P ? 780 kPa, the respective properties of the solvent-saturated and flashed-off heavy oils taken from the upper and lower parts are different to large extents. This may be because asphaltene aggregation occurs in the solvent-saturated heavy oil and some heavy components move downward to the bottom of the saturation cell. If the saturation pressure is increased to P=850 kPa, asphaltene precipitation occurs and some large asphaltene particles are deposited onto the acrylic windows of the saturation cell. Although the physicochemical properties of the solvent-saturated and flashed-off heavy oils measured by using different experimental methods show variable sensitivities to the asphaltene precipitation, its onset can be successfully detected in practice. Introduction Western Canada has tremendous heavy oil and bitumen deposits with estimated original-oil-in-place (OOIP) of 2.5 trillion barrels. They hold great potential to meet the future hydrocarbon fuel demand, while the conventional petroleum reserves are being depleted. Nevertheless, how to effectively and economically recover heavy oil and bitumen remains a technical challenge due to their extremely high viscosities. At present, thermal-based heavy oil recovery methods are often applied because they can dramatically reduce the heavy oil viscosity. However, large heating and water source requirements, heat losses to thin oil formations, and water treatment cost make these tertiary oil recovery methods ineffective and uneconomical. Solvent-based heavy oil recovery processes have recently gained more and more attention because of their distinct advantages over the thermal-based heavy oil recovery methods. In a typical solvent-based heavy oil recovery process, such as vapour extraction (VAPEX) process, gaseous condensable solvents, together with non-condensable carrier gases, are injected and dissolved into the heavy oil to dramatically reduce its viscosity. In some cases, the heavy oil viscosity reduction due to sufficient solvent dissolution may be comparable to that achieved by applying the thermal-based heavy oil recovery methods. Another major advantage of the solvent-based heavy oil recovery processes is asphaltene precipitation through sufficient solvent dissolution so that the heavy oil in the reservoir is insitu upgraded. The precipitated asphaltenes are deposited onto the sand grains and thus left behind in the reservoir. The produced heavy oil has a much lower viscosity and better quality in comparison with the original crude heavy oil.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Physical Modeling of Heavy Oil Production Rate in a Vapour Extraction Process
Zhang, H. (Petroleum Technology Research Centre (PTRC), University of Regina) | Luo, P. (Petroleum Technology Research Centre (PTRC), University of Regina) | Gu, Y. (Petroleum Technology Research Centre (PTRC), University of Regina)
Abstract Vapour extraction (VAPEX) process is a promising heavy oil recovery technology because it can cause significant viscosity reduction through sufficient solvent dissolution and possible asphaltene precipitation. Although the VAPEX process has been extensively studied in the past two decades, it is still a challenging technical task to predict its stabilized oil production rate. It has been reported in the literature that the predicted oil production rate can differ from the measured oil production data by several factors to one order. In this paper, physical modeling is conducted to accurately measure the stabilized heavy oil production rate, which is then compared with the theoretical prediction. In the experiment, a rectangular sand-packed VAPEX physical model is used and its porosity and permeability are measured prior to the VAPEX tests. A butane mixture is chosen as a gaseous solvent to extract heavy oil at a constant pressure slightly lower than its dew-point pressure and a constant temperature. The heavy oil VAPEX process is visualized to determine the so-called vapour chamber rising, spreading and falling phases. In particular, the stabilized heavy oil production rate during the vapour chamber spreading phase is measured. Theoretically, the modified Butler- Mokrys analytical model is applied to predict the stabilized heavy oil production rate. It has been found that the modified Butler- Mokrys analytical model can give a good prediction of the stabilized heavy oil production rate in the vapour chamber spreading phase. It is worthwhile to emphasize that the measured permeability of the physical model, the measured solubility and the effective diffusivity of the solvent in the heavy oil should be used in the theoretical prediction. Introduction Effective and economical recovery of heavy oil and bitumen from a large number of heavy oil and bitumen reservoirs in Western Canada becomes a key technical issue because the conventional crude oil production declines rapidly. In 2003, for the first time, the heavy oil and bitumen production exceeded the conventional crude oil production in Alberta. The high viscosity and low mobility of heavy oil and bitumen cause their primary recovery to be as low as 6~8 percent of the original-oil-in-place (OOIP) . As a secondary recovery method, waterflooding may produce some incremental oil. Unfortunately, the overall incremental recovery for waterflooding is rather low due to the quick water breakthrough caused by extremely high mobility ratio. Thermal-based tertiary recovery processes, such as, cyclic steam stimulation (CSS), in-situ combustion (ISC), steam-assisted gravity drainage (SAGD), are currently being applied to enhance heavy oil and bitumen recovery. The maximum oil recovery of a typical CSS process usually does not exceed 20 percent and a subsequent steam flooding process is required to produce the remaining oil in the reservoir. In general, the ISC process is not suitable for recovering highly viscous crude oil (say ฮผ?> 1000 mPa's) . The SAGD process is rather successful in exploiting the heavy oil and bitumen resources.
- North America > United States (0.94)
- North America > Canada > Alberta (0.50)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.90)
Abstract During a solvent-based heavy oil recovery process, such as vapor extraction (VAPEX), a condensable solvent is injectedinto a heavy oil reservoir. Solvent dissolution into heavy oil and possible asphaltene precipitation drastically reduce its viscosity so that the diluted heavy oil can flow towards a production well. In the past, several physical modeling studies have shown that the produced heavy oil has much less amount of heavy components than the original heavy oil. This phenomenon is often referred to as in-situ upgrading. In this paper, a series of laboratory experiments is conducted under reservoir conditions to quantify the in-situ upgrading of heavy oil due to the solventdissolution and asphaltene precipitation by using a pure solvent (propane) and a mixture solvent (70 mol% methane + 25 mol% propane + 3.5 mol% n-butane + 1.5 mol% iso-butane), respectively. It is found that after a solvent is made in contact with heavy oil at a relatively high pressure for a sufficiently long time, the solvent-heavy oil system at equilibrium state can be roughly divided into three different layers. The top layer is a solvent-enriched liquid phase, the middle layer comprises heavyoil with the dissolved solvent and the bottom layer mainly consists of heavy components. The solvent-heavy oil mixtures inthese three layers show rather different chemical and physical properties, such as solvent concentration, carbon number distribution and viscosity. The top layer has the highest concentrations of solvent and light components and the lowest viscosity of heavy oil even after its dissolved solvent is flashed off. The heavy oil in the middle layer has similar carbon number distribution to the original heavy oil. The bottom layerhas the lowest solvent concentration and the highest concentration of heavy components. The heavy oil in the bottom layer after its dissolved solvent is flashed off has much higherviscosity than the original heavy oil. These experimental results indicate that in a solvent-based heavy oil recovery process, the solvent-heavy oil mixture in the top and middle layers can berecovered because of its lower viscosity, whereas the heavy oil in the bottom layer may be left behind in the heavy oil reservoir because of its higher viscosity. In this way, the produced heavy oil is in-situ upgraded during the solvent-based heavy oil recovery process. Introduction Western Canada has tremendous heavy oil and bitumen Deposit. Approximately 70% to 80% of the original-oil-inplace (OOIP) remains unrecovered at the economic limit after the cold production. Heavy oil contains a large portion of heavy components, which are the major reason for its high viscosity (>1,000 mPa?s) and low API gravity (<20 ยฐ API gravity) . Heavy oils and bitumen are highly viscous so that they cannot be recovered by using some conventional recovery techniques for medium and/or light oils. In practice, thermal methods are often used because they can dramatically reduce heavy oil viscosity. However, the majority of Canadian heavy oil reservoirs cannot be exploited economically by using thermal methods alone due to thin pay zones and/or bottom water aquifer.
- North America > Canada (1.00)
- North America > United States > Oklahoma (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract In this paper, a new experimental technique is developed tostudy the solvent mass transfer in heavy oil and the resultant oil swelling effect by applying the dynamic pendant drop volume analysis (DPDVA). In the experiment, a pendant drop of heavy oil is formed inside a visual high-pressure cell, which is initially filled with a solvent (e.g., propane) at the desired pressure and temperature. As the solvent gradually dissolves into heavy oil, the volume of the pendant oil drop keeps increasing due to the oil swelling effect. The sequential digital images of the dynamicpendant oil drop are acquired by applying computer digital image acquisition technique. Such acquired digital drop images are analyzed to determine the interfacial profiles and the volumes of the dynamic pendant oil drop at different times. Theoretically, a mathematical model is formulated to describe the solvent mass transfer and the oil swelling effect. This model shows that the volume change of the dynamic pendant oil drop solely depends on the diffusion coefficient of the solvent in heavy oil and the oil swelling factor. Therefore, the diffusion coefficient of the solvent in heavy oil and the oil swelling factor can be determined by finding the best fit of the theoretically predicted volumes of the dynamic pendant oil drop to the experimentally measured data. Experimental tests are conducted for propane-heavy oil system at constant temperatureof T=23.9 ยฐ C and constant pressures of P=0.4, 0.5, 0.6, 0.7, 0.8, and 0.9 MPa. It is found that both the diffusion coefficient and the oil swelling factor of propane-heavy oil system increasewith pressure. The major advantage of this newly developed DPDVA technique is that simultaneous measurements of solvent diffusivity in heavy oil and oil swelling factor can be completed within two hours at a pre-specified constant pressureand temperature. Introduction In the vapor extraction (VAPEX) process, a solvent (e.g., methane, ethane, propane, butane, carbon dioxide, or their mixtures) at a pressure close to its dew point is injected into a heavy oil reservoir. Previous studies have already shown that molecular diffusion of the injected solvent in heavy oil plays a vital role in the VAPEX process. Thus the diffusioncoefficient of the solvent in heavy oil under the actual reservoir conditions becomes an important parameter in the reservoir simulation and field design of the VAPEX process. In the literature, there are several experimental methods formeasuring solvent diffusivity in heavy oil. These experimentalmethods can be roughly categorized into conventional and nonconventional methods. Conventional methods involve compositional analysis of liquid samples taken from the solvent-heavy oil mixture at different times and locations during a diffusion test. These methods are expensive, intrusiveand time-consuming, especially if the diffusion test is conducted at high pressures. In addition, compositional analysis of solventheavy oil mixture is prone to large experimental error. Nonconventional methods measure the change of a property of the solvent-heavy oil system during the molecular diffusion process.
- North America > United States (1.00)
- North America > Canada (0.69)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract In this paper, an experimental technique is developed to study the interfacial tension phenomenon and visual interactions of crude oil-brine-CO2 systems at different pressures and temperatures. The major component of this experimental set-up is a see-through windowed high-pressure cell. By using the axisymmetric drop shape analysis (ADSA) for the pendant drop case, this new technique makes it possible to determine the interfacial tension (IFT) and to visualize the interfacial interactions among crude oil, brine and CO2 under practical reservoir conditions. More specifically, IFT of the crude oil-brine-CO2 system is measured as a function of pressure and temperature, respectively. For the crude oil-CO2 system, it is found that the dynamic IFT gradually reduces to a constant value, i.e., the equilibrium IFT. Meanwhile, a number of important physical phenomena are observed after the crude oil is made in contact with CO2. In particular, the oil swelling effect, light-ends extraction, initial turbulent mixing and wettability alteration are the major characteristics of the CO2 flooding processes. There always exists a constant low IFT (i.e., partial miscibility) as long as the pressure is higher than a threshold value. No ultra low or zero IFT between the crude oil and CO2 is found, regardless of the operating pressures and temperatures tested in this study. For the crude oil-brine-CO2 systems, wettability between crude oil and needle surrounded by CO2-saturated brine phase is different from that of the crude oil-CO2 systems. In addition, immiscibility between CO2- saturated crude oil and CO2-saturated brine is still observed at P=28.196 MPa and T= 58?C. Therefore, this laboratory study shows that partial miscibility between the crude oil and CO2 occurs in the reservoirs and that wettability alteration may considerably improve the oil recovery in a water-wet reservoir during CO2 flooding processes. Introduction CO2 flooding is considered to be one of the most promising enhanced oil recovery (EOR) techniques because it not only effectively enhances oil recovery but also considerably reduces greenhouse gas emissions. There have been extensive laboratory studies and field applications of CO2 EOR processes in the past five decades. It has been found that these processes can enhance oil recovery normally by up to 8โ16% of the original oil in place. In the CO2 flooding processes, saturation distribution and flow behavior of crude oil, gas and brine is controlled largely by the interfacial interactions among crude oil, reservoir brine, CO2 and reservoir rocks, such as interfacial tension (IFT), wettability, capillarity and dispersion]. Also, field applications show that early breakthrough, unstable fronts and injectivity loss are three common major problems encountered in the CO2 EOR processes. Physically, these three unresolved technical problems are closely related to the interfacial properties of crude oil-fluid-rock systems in the reservoirs. Therefore, it is important to accurately describe the interfacial interactions of the crude oil-fluid-reservoir rock systems with dissolution of solvents, such as CO2, under reservoir conditions. In general, the ultimate oil recovery in the CO2 flooding processes is dependent on the oil viscosity reduction, oil swelling effect and changes of interfacial properties between crude oil and CO2].
- North America > United States (1.00)
- North America > Canada (0.69)
- Research Report > New Finding (0.35)
- Overview > Innovation (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.49)
Abstract Alkali plays a unique role in the alkaline/surfactant/ polymer (ASP) flood processes. It has been well recognized that the injected alkali can generate the surfactants in situ by reacting with the organic acids in the crude oil. Such generated surfactants will reduce the interfacial tension (IFT) and mobilize the residual oil in a reservoir. On the other hand, the reservoir rock surface will become more negatively charged at higher hydroxyl ion concentrations. These ions adsorbed onto the rock surface not only deter the adsorption of anionic chemicals, such as anionic surfactants and polymers, but also alter its wettability. In this paper, an experimental study is conducted on the interactions of alkaline solutions with oil-brine-rock systems in ASP flood processes. First, the total alkaline loss is determined by measuring the alkaline concentration change. Physically, alkaline loss is caused by the pair interactions of alkalioil, alkali-brine, and alkali-rock, respectively. The alkaline loss due to the alkali-oil chemical reactions mainly depends on the acid number of the crude oil. The alkaline loss also occurs when alkali reacts with the divalent cations in the brine, such as Ca and Mg. The adsorption of alkali onto the rock surface is usually considered as the largest portion of the total alkaline loss, given the enormous rock surface area available in a reservoir. In addition, the silicon dissolution caused by the alkali-rock chemical reactions is quantified in terms of sand loss. Secondly, the IFT is measured as a function of alkaline concentration by using the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case. Thirdly, the interactions among alkali, surfactant and polymer are studied. Furthermore, the coreflood tests of alkaline flood are performed and the detailed coreflood results show that alkaline flood can enhance oil recovery up to 12.7%. It is also found that the alkali remaining in the produced fluids can be effectively reused for further enhancing oil recovery. Introduction It is well known that a typical oil recovery for waterflooding is usually around 30-40%. Thus, there is still 60-70% original oil in place (OOIP) left in the reservoir in the form of oil ganglia. This residual oil is trapped mainly due to high capillary pressure, i.e., high IFT at the oil-brine interface. Further oil recovery can be enhanced by increasing the oil displacement efficiency and the sweep efficiency simultaneously . ASP flood is a promising EOR technique applied to recover the residual oil. The major EOR mechanisms of ASP flood are described as follows. In conjunction with the added surfactant, the surfactants generated in situ by the chemical reactions between the injected alkali and the natural organic acids in the crude oil can result in ultralow IFT. The ultra-low IFT at the oil-brine interface helps to emulsify and mobilize the residual oil in a reservoir. In addition, the reservoir rock surface becomes more negatively charged at higher hydroxyl ion concentrations. These negatively charged ions not only prevent the adsorption of anionic chemicals, such as anionic surfactants and polymers, but also change the wettability of the rock surface
- North America > United States (0.69)
- Asia > China (0.47)
- Research Report > New Finding (0.87)
- Research Report > Experimental Study (0.68)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract Alkaline flood is a cost-effective enhanced oil recovery (EOR) process, particularly suitable for acidic oil reservoirs. After alkaline solution is injected into an oil reservoir, some surfactants can be generated in situ by the neutralization of the injected alkali with the organic acids in crude oil. Such generated surfactants can be absorbed at the oil-water interface and dissolved in the bulk aqueous phase and/or in the oil phase as well, depending on their affinities for the aqueous and oil phases. The distributed surfactants change the interfacial tension (IFT) between the oil and aqueous phases. Therefore, a thorough study of this dynamic IFT phenomenon improves one's understanding of alkaline flood process. In this paper, the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case is employed to measure the dynamic IFTs between crude oil and different aqueous solutions. It has been found that the measured IFT changes with time and this dynamic IFT phenomenon is interpreted in terms of the surfactant generation and distribution at the oil-water interface, as well as the diffusion processes in the bulk phases. Meanwhile, it has also been observed that the volume of the pendant oil drop in an alkaline solution decreases with time. The so-called oil shrinking effect has been quantified and three possible mechanisms for this effect are proposed. These mechanisms include oil volatility in an aqueous solution, chemical reactions between the oil phase and the alkaline solution, and possible migration of water micro-droplets from inside the oil drop to the alkaline solution. More specifically, the dynamic IFT phenomenon and the oil shrinking effect are examined for a series of aqueous systems, such as deionized ultrafiltered water, and the alkaline solutions with different alkali concentrations. This study not only provides an improved understanding of the interactions between the oil and alkali but also helps to fully develop the oil recovery potential of an alkaline flood process. Introduction It has long been recognized that alkaline flood is a cost-effective enhanced oil recovery (EOR) process, particularly suitable for acidic oil reservoirs. When the acidic crude oil and alkali are encountered in the alkaline flood, one of the most important phenomena in this process is the interfacial tension (IFT) reduction due to the in situ generation of surfactants by the chemical reaction of the organic acids in the crude oil and the alkali in the flood water. Such generated surfactants can be absorbed at the oil-water interface and gradually dissolved in the bulk aqueous phase and/or in the oil phase, depending on their affinities for the aqueous and oil phases. Thus, IFT between the oil phase and alkaline solution changes during an alkaline flood and finally reaches an equilibrium value. In the literature, some efforts were made to study this kind of dynamic IFT phenomenon. An experimental study was carried out by Reisburg and Doscher [1], who examined the effects of interface aging and sodium hydroxide concentration on IFT.
- North America > Canada (0.47)
- North America > United States (0.46)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.86)
ABSTRACT With the development of waterflooding in an oil field, water breakthroughsare a common problem. Polymer solutions are widely applied to resolve thewater-channeling problem in a deep formation. In practice, polymers are used asagents in deep formation treatment either to block in-depth high permeabilityzones or to lower water mobility. However, for in-depth profile modification, apolymer solution has to be injected at a relatively high concentration so thatsuch treatment sometimes becomes uneconomical. On the other hand, polymerflooding is ineffective primarily due to the viscosity loss caused bymechanical and chemical degradations. This paper presents a weak gel system, which can be used as an in-depth profile modification agent and as an oildisplacement agent in a heterogeneous reservoir. This gel has relatively lowstrength but can still be cross-linked in the reservoir formation. Themechanisms of weak gel system are described in detail. In addition to studyingthe effects of polymer concentration, cross-linker concentration, temperatureand pH value on gelation time, rheological behavior, gelation ranges and gelstrength are examined. The coreflood results not only provide evidence that theweak gel acts both as an in-depth profile modification agent and as an oildisplacement agent but show an enhanced oil recovery as well. Furthermore, thepilot tests have been performed in four areas of Gudong oil field and Gudao oilfield in China since 1992. As a result, the injection pressure has beenincreased for all testing wells and the field water-cut has been reduced. Bythe end of 2001, the accumulative incremental oil production has been over58,000 tons.
- Asia > China > Shandong Province (0.34)
- Asia > China > East China Sea (0.34)
- North America > United States > Texas (0.28)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Shandong > Bohai Basin > North China Basin > Gudong Field (0.99)
- Asia > China > Shandong > Bohai Basin > Jiyang Basin > Gudong Field (0.99)
- (4 more...)
Abstract Although modern reservoir management requires integrated production optimization for the productioninjection operation systems (PIOS), a variety of methods have been applied to implement "local" rather than "global" optimization. There have been no systematic methods to optimize the PIOS by adjusting the injection and/or production rates at a field-scale level. This paper presents an efficient global optimization technique to adjust the PIOS for hydrocarbon reservoirs. A generalized production performance model is developed for flowing and artificial lift methods and has been applied to more than forty oil fields. This generalized model can be coupled with reservoir models to implement optimum control of field-wide production and injection rates at different development stages. Simulated annealing algorithm is employed to optimize the PIOS by integrating a reservoir model with performance models which consider multiple injectors and producers. Such an integrated technique can optimize the PIOS in a fixed well-group and/or a field under different constraints. It has been applied to a water-alternating-gas miscible flooding reservoir over five years. The field performance shows that the reservoir pressure is maintained above the minimum miscible pressure and that the injection and production performance is kept in an optimum range. In addition, the field water-cut remains at zero water-cut stage and the gas-oil-ratio is slightly higher than the original value. The injection and production rates are properly adjusted in the field operations so that the reservoir life is extended and the oil recovery is improved. Introduction Integrated reservoir management has been increasingly applied to maximize economical recovery of oil and gas . Although the production-injection operation systems (PIOS), which consists of producers, reservoirs, injectors and surface facilities, is the key knot of the integrated reservoir management, each component is usually considered individually in both design and operations. Physically, each engineering function models and optimizes its component of the systems on the basis of "local" other than "global" criteria . After an oil field is put into production, it will be transformed from a static system into a dynamic one. Thus there is a need to execute global optimization for the PIOS by dynamically integrating all the components in the whole system. The optimum control of fluid movement in a reservoir is the focus and challenge in the development of petroleum resources . From the viewpoint of cybernetics, the underground reservoir is a system that can be controlled properly. The injected fluids, including gas and water, are considered as the input, whereas the produced fluids are treated as the output of the system. Furthermore, it is a challenging task to solve fieldoperating problems and develop the field-wide production potential by integrating the injection and production with reservoir performance . In practice, the injection and production rates can be adjusted in individual wells for the PIOS, though field development is essentially a dynamic process. So far there have been no systematic methods to optimize the PIOS by adjusting the injection and/or production rates at a fieldscale level. Economic optimization of the PIOS is an ultimate goal of the reservoir management.
- Asia > China (0.47)
- North America > United States (0.29)
- North America > Canada (0.29)
- South America > Argentina > Mendoza > Neuquen Basin > Cerro Fortunoso Field (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Pubei Field (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- (2 more...)
Abstract There are many naturally fractured reservoirs in the world, but few of them are optimally developed. In fact, it is difficult to characterize the naturally fractured reservoirs and predict the oil production, needless to mention the determination of appropriate production operation methods (POMs). Although there have been some formulas for evaluating well performance, a few were derived on the basis of production test data. In this paper, several general formulas are developed for evaluating inflow performance of both vertical wells and horizontal wells, based on the production test data obtained from three naturally fractured reservoirs. The influence of rock compaction and the inertial flow resistance in naturally fractured reservoirs are considered in these equations. Furthermore, theoretical models are also presented, into which reservoir engineering, production performance and surface facility performance are incorporated. These models are then applied to evaluate and determine the oil well POMs for two naturally fractured reservoirs. It has been shown from these two field applications that stable flowing performance, including its ceasing conditions, can be predicted. And artificial lift methods such as sucker-rod pumping can be efficient under certain reservoir conditions. The detailed field application results indicate that most of POMs determined from the theoretical models are technically feasible and economically viable. Introduction Naturally fractured reservoirs are found in all types of lithologies and throughout the geological stratigraphic columns. However, initial high oil rates have misled engineers in many instances to overestimate production forecasts of wells. Thus development of the naturally fractured reservoirs results in numerous economic failures. Meanwhile, field practices show that selection of appropriate production operation methods (POMs) is critical to the long-term profitability of most producing wells. An improper choice can not only substantially reduce production but also greatly increase operating costs. Once a type of POM has been determined to install on a producing well, usually the POM is unchanged, whether it was and still is the optimal choice under existing conditions. Therefore, It is essential that both accurate prediction of well inflow performance and appropriate selection of POMs be of great benefit to the optimal development of the naturally fractured reservoirs. In general, it is difficult to characterize the naturally fractured reservoirs, predict the oil production and further determine suitable POMs. The well inflow performance relationship (IPR), which represents the well's ability to produce fluids, is the first component to be considered in the process of selecting POMs. In the literature, although there have been some formulas for evaluating well performance, few were derived on the basis of production test data. Gubkina presented a formula for evaluating vertical well inflow performance in the naturally fractured reservoirs, which was later improved by Bacnev et al.. However, the effect of well completeness on well inflow performance was not accounted for. To evaluate the horizontal well inflow performance in naturally fractured reservoirs, Joshi's formula is modified to achieve better forecasts.
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.28)
- Asia > China > Shandong Province (0.28)
- Geology > Geological Subdiscipline > Stratigraphy (0.54)
- Geology > Rock Type (0.48)
- Asia > China > Xinjiang Uyghur Autonomous Region > Pubei Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- North America > United States > Louisiana > China Field (0.97)