Search

Introduction "PANDAMONIUM"-a wild, exciting time is in store for China's oil patch. Plans to triple the production rate to 6 million bbls per day by the year 2000, and to triple gas production to 3.7 bcf per day in the next five years, clearly indicates the Land of the Pandas is where the action is, both now and well into the next century. Where will the Canadians be? I believe we can be right in the middle of China's oil boom. In China, the giant panda symbolizes strength, bravery and good fortune. And the panda and the Canadian oilman have certain similarities. They tend to be industrious, quietly and efficiently going about their tasks, in a risk-oriented environment. The result is that use of Canadian technology, equipment, personnelnd expertise are steadily on the rise in China. This paper highlights a few of the Canadian companies and their people who have won projects in China through hard work, innovative selling, tough negotiating, persistence and patience. NOVA Corporation of Alberta, Calgary (Petrochemicals, pipeline engineering consulting, operational training, pipeline-related products, heavy oil production consulting and telecommunications) NOVA'S marketing approach to China started in 1974 with the hosting of senior technical delegations from the Pipeline Bureau and Ministry of Petroleum Industry (MOPI) on tours of NOVA'S operating pipeline systems. Many exchange visits followed, and over the years a relationship of trust, friendship, credibility and continuity was established. From 1974 to 1988, 115 Chinese delegations visited NOVA. In 1983 the first commercial contract was signed to train four Chinese pipeline engineers on the NOVA system in Alberta in the operation of pipeline pigging. NOVA is now providing to China:Pipeline engineering and hands-on operational training in both Canada and China through Novacorp International Consulting Inc. (Fig. 2);Grove values and surge relievers made in Oakland, California;Cold-weather heavy oil production technology for the Karamay field in northwest China through Husky Oil;Three types of polyethylene. low density, high density and linear low density polyethylene resin produced by Novacor Chemicals in Joffre, Alberta and Moore Township, Ontario. NOVA chairman Bob Blair reflects on NOVA's China's activities:"we wanted to establish ourselves as a leader ... we could see a future for our kind of work in China. Right now, China is the most ambitious country in the world in terms of oil and petrochemical production and development." NOVA is a strong position to participate in China's long-term economic growth and energy. The following chronology of events illustrates NOVA's China activities from 1974 to present: NOVA's China Activities (Fig. 3)1974-Initial meeting with Ministry of Petroleum Industry (MOPI) and Pipeline Bureau officials.1982-Signing of cooperation agreements between Novacorp, China Petroleum Engineering Construction Corporation (CPECC), and China Offshore Oil Development and Engineering Corporation (COODEC).1983-Training of engineers from China National Offshore Oil Corporation (CNOOC) and engineers from the Pipeline Bureau of NOVA's pipeline operations.

Abstract This paper presents the results of a computer study which leads to the optimum design of a production system for flowing wells subjected to a natural production system for flowing wells subjected to a natural water drive. The results presented consist of a series of graphs which are derived from an analysis of the inflow performance relationships, vertical lift performance, choke performance, horizontal flow performance, and the thermodynamic conditions of the surface conditioning equipment such as separator and flow lines. The Hagedorn and Brown correlations and the Beggs and Brill correlations are utilized to determine pressure drop for vertical lift and horizontal flow performance for multiphase flow. Using these correlations and assuming a flow rate and starting from the separator, pressure losses are calculated along the flowline to the wellhead, across the choke, and down the tubing to the tubing intake. Output from the analysis results in an optimized system design which maximizes production for a set of reservoir conditions and surface constraints. An example well problem are presented which demonstrate the applicability and versatility of the computer analysis. An analysis is also presented to assess the sensitivity of various parameters upon well performance. Such parameters as flowline size, separator temperature and pressure, choke size, tubing size, water oil ratio, gas oil ratio, productivity index, oil gravity and fluid slippage are productivity index, oil gravity and fluid slippage are considered in the sensitivity analysis. The results of this analysis and the data presented provides the production engineer with a presented provides the production engineer with a technique for designing a system which will optimize production from a given well. The approach is production from a given well. The approach is general in that the outputs from the analysis provides the engineer with a set of curves and graphs to assist in making a final decision concerning a specific well or group of wells. Introduction Considerable information has been published concerning the analysis and design of production systems for oil and gas wells. However, much of this information appears to be used sparingly since a great deal of time and effort must be expended in order to use it effectively. The purpose of this paper is to present a methodology inherent in a computer program present a methodology inherent in a computer program developed to provide the engineer a tool for performing analysis and design synthesis in order to arrive performing analysis and design synthesis in order to arrive at an optimum production system for a well. The complete details including the computer code is given in reference 1 and only a summary of the results are presented in this paper. It is recognized that presented in this paper. It is recognized that several petroleum companies or independent consulting firms may have similar in-house capabilities as are described in this paper but to the authors knowledge a complete description including a computer code has not been made available to the industry. In addition, the integration of generalized inflow performance analysis, vertical multiphase flow, choke performance, flow line conditions has yet to appear in the literature in a systematic manner. The best known source of information concerning all these aspects can be found in reference 2 and 3. However, neither of these references presents a complete computer optimization scheme for analyzing total well performance. In order to evaluate the performance of a naturally flowing well it is necessary to divide the performance into three distinct stages, which are performance into three distinct stages, which are studied separately and finally linked together in order to efficiently evaluate the overall performance of a given well. The three principle stages are inflow performance, vertical multiphase flow, and horizontal performance, vertical multiphase flow, and horizontal multiphase flow. Inherent within these three stages are the surface choke performance and surface facility constraints. Hence, the main purpose of this paper is to present a logical methodology to design the initial production system for a flowing well and to reasonable predict its future performance. These operations arePredict the optimum flowrate for specific reservoir conditions. P. 297

Various suggested primary and secondary petroleum migration mechanisms are reviewed, with emphasis on hydrocarbon solubilities in water. Primary migration of crude oil in aqueous solution is shown to be not possible because of (1) the very low solubilities of high-molecular-weight hydrocarbons, compared with low-molecular-weight hydrocarbons; and (2) the markedly higher solubilities (185 to 650 times) of aromatic hydrocarbons with up to 20 carbon atoms in the molecule, compared with the corresponding carbon number alkanes. Thus, hydrocarbons in water solution in equilibrium with crude oils consist typically of more than 60% benzene plus toluene in the C6+ fraction. However, the concentrations of benzene and toluene in crude oils are typically 1% or less. The low-molecular-weight alkanes (C1-C5) have high solubilities in water, and natural gas may migrate dissolved in water. Migration of oil solubilized in surfactant micelles is not feasible, because a large amount of surfactant would be required to attain a critical micelle concentration (CMC). The size of micelles, if formed, would be too large to pass the small pore throat constrictions in source rocks. Migration by oil droplet expulsion also is not feasible, because of the difficulty of overcoming the high interfacial forces of small drops in small pores. Even if interfacial tensions between oil and water could be lowered sufficiently for oil flow, the source rock would be required to convert at least 7.5% organic matter by volume in order to attain 30% oil saturation required for separate phase flow. Attaining higher oil saturations required for "squeezing" oil from pores would require even higher organic matter concentrations. If oil expulsion did occur, the residual oil saturation would be at least 20% in all source rocks after oil migration. Such concentrations have not been universally observed. All processes whereby generated petroleum enters into or moves with water do not seem possible, because of chemical and physical constraints. Petroleum, in all likelihood, is generated in and flows from source rock in a three-dimensional organic matter (kerogen) network. Scanning electron micrographs clearly show a three-dimensional kerogen network after minerals have been removed by acid treatments. Petroleum flowing End_Page 1-------------------------- in this hydrophobic network is not subject to interfacial forces until bubbles of gas or droplets of oil enter the much larger water-filled pores in the reservoir rock. Oil will flow under the same forces of compaction or pressure developed by gas formation, or by volume expansion associated with petroleum generation. Oil and water flow are independent processes; that is, water flow is not required for primary or secondary petroleum migration. The oil saturation in the kerogen for oil flow to occur is indicated to be from 2 to 10%, based upon hydrocarbon analysis for organic matter in a large number of suspected source rocks. The lower limit of 0.5 to 1% organic matter content for potential source rocks may be due, not to lack of generation potential, but to lack of a three-dimensional kerogen network in rocks containing less organic matter. Secondary migration of separate-phase oil and gas should occur by buoyancy, when their saturations attain 20 to 30% along the upper or lower surface of the reservoir rock. Petroleum entering at the lower surface would cross the rock when the buoyancy head became sufficient for separate-phase flow. This cross-formational flow would occur at occasional intervals. Migration would occur along the upper few centimeters in the reservoir rock from source to trap, thereby providing an efficient migration mechanism. The volume of reservoir rock that attains oil or gas saturation during secondary migration should be small. Water flow is not required. In contrast, secondary migration of hydrocarbons in solution (gas, oil, and micelles) would be very inefficient and require large volumes of water. Secondary migration by solution would require all pores in a reservoir rock to attain 20 to 30% gas or oil saturation before separate-phase flow could occur. Smaller pores may attain higher gas or oil saturations. If separate-phase flow were not attained, petroleum would be locked in the pores and would not be available to form gas or oil reservoirs in trap positions. At 4572 m (15,000 ft) and a temperature of 160°C, a flow of about 90 pore volumes (PV) of gas-saturated water would be required to attain 30% gas saturation. At 1524 m (5000 ft) and 60°C, 200 PV flow would be required. Moving oil in solution would require much more water: 15,000 PV at 4572 m, and 200,000 PV at 1524 m. Limited solubility data suggest that even at 7929 m (26,000 ft) and 270°C, about 4500 PV of hydrocarbon-saturated water would be required to attain an oil saturation of 30%. Cores taken from any portion of the reservoir rock along the secondary migration pathway should show this residual gas or oil saturation. Recovered water should always contain the equilibrium concentrations of each individual hydrocarbon based upon its pure solubility in water and its mol fraction concentration in the separate gas or oil phase present in the rock pores. This has not been generally observed. End_Page 2-------------------------- In actuality, water flow probably disperses water-soluble constituents instead of concentrating them in reservoir traps.

ABSTRACT A simple, mechanistically based scheme for the calculation of the pressuredrop in wells producing oil and gas in the single-phase liquid, bubble and slugflow patterns is described and checked with independent field data. The schemeis based on an identification of the flow pattern through a modification of theflow pattern map of Govier, Radford and Dunn and the application of themechanical energy balance in a form appropriate for the flow pattern assuggested by Govier and Aziz. Predictions for some 48 wells are compared withfield data and with the predictions of Orkiszewski, Duns and Ros, and Hagedornand Brown. The proposed method gives results at least as good as any of theothers, is more soundly based on the mechanism of flow and is independent ofthe data with which it is confirmed. A computer program for the method and a typical printout are given. INTRODUCTION Many methods have been proposed for the estimation of the pressure drop inwells which produce a mixture of oil and gas. These are reviewed in detail by Govier and Aziz. Most of the methods are strictly empirical, but for certain ofthe flow patterns which may be encountered methods based on the mechanism offlow may now be developed. This is especially true for the bubble and the slugflow patterns and, as will be discussed in a following paper, the annular-mistflow pattern encountered with gas-condensate wells. Orkiszewski has developed a pressure drop prediction scheme based on anidentification of the flow pattern and the application of selected mechanisticand empirical methods to the individual flow patterns. His original appraisalincluded, among others, the Poettmann and Carpenter and related correlations.The most accurate methods, the Duns and Ros and the Hagedorn and Brown werethen tested along with his own scheme against 148 well conditions.Orkiszewski's comparison showed that his method gave improved accuracy overthat of Duns and Ros and Hagedorn and Brown. Espanol et al confirmedthis with data from 44 different wells.

In this paper, the authors treat the problem of the back-streaming of oil vapour toward the fine pressure side in an oil diffusion pump and analyse the source of back-streaming into the following: 1 The drains on the jet surface 2 The vaporization of cold oil drains on the upper wall of a pump cylinder 3 The scattering of oil vapour stream 4 The reflection of oil vapour stream. To measure the back-streaming of vapour, the authors employ metal probes located in the radial direction of the cylinder at the pump-head, and determine the quantity of the back-streaming by the weights of the oil condensed on the probe surface in the unit time. The authors concluded that the back-streaming of oil vapour is mainly caused by the oil drains on the jet surface, and not so much by the scattering, reflection and the evaporation of cold oil drain. The evaporation of oil from the cold surface can be measured by means of some baffles, but the scattering and reflection are not separated from each other. Nevertheless, the amount of the oil back-streaming caused by the scattering and reflection is only three times as large as that caused by the evaporation from the cold surface.

Abstract A simplified mathematical model is developed to determine the amount of oil that survives passage to a hot fracture boundary in an underground retorting process in oil shale. Combustion at or near a fractured surface, heat conduction, oxygen diffusion, reaction of oil and oxygen, and perpendicular oil flow by diffusion and perpendicular oil flow by diffusion and convection toward the hot boundary are considered. Appropriate assumptions are employed to arrive at upper bounds on the predicted recovery. Significant amounts of oil production are unlikely when the fracture temperature approaches 2000 degrees F. However, if the temperature is 1200 degrees F. or lower, the calculated upper bound is 64%. When more realistic assumptions are invoked, the computed results indicate no oil recovery. The effects of oil migration velocity and the kinetic parameters were studied. Predicted recoveries were highly sensitive to the activation energy for temperatures below 2000 degrees F We conclude that underground combustion in oil shale employing hydraulically or electrically created fractures apparently is not technically feasible unless appropriate means of reducing temperatures are employed. It appears that massive rock breakage is necessary to achieve substantial amounts of oil production. Introduction The possibility of underground retorting of oil shale appears attractive since mining, crushing, and spent shale disposal are not involved. However, it is necessary to induce a flow path in the rock since oil shale usually has no primary permeability and porosity (vugular porosity excluded). To porosity (vugular porosity excluded). To accomplish this, hydraulic fracturing, nuclear detonation, and electro-fracturing have been suggested. A number of thermal processes, such as hot fluid injection, forward combustion, reverse combustion, and conduction heating, can presumably be conducted within a single fracture presumably be conducted within a single fracture or system of fractures. Other methods have been proposed which combine two or more of these basic processes. The success of any of the above processes will necessarily hinge on whether or not sufficient quantities of the liquid product can be recovered. In most cases, the system of fractures created in the shale must serve as the flow path for the produced as well as the injected fluids. Some or all of the produced fluids will frequently pass through high temperature zones to reach the fractures. To make intelligent performance predictions, it is important to know if the residence time and temperature levels will result in severe reduction in oil yield by destructive distillation and oil burning.

It is suggested that greater recovery of oil will be obtained: (1) by maintaining the pressure of the reservoir at high values, (2) by keeping gas, oil, and water segregated in their natural relation as far as possible. To bring about these conditions, low rates of flow are essential, especially in water-drive fields. Likewise, free gas and water should not be produced. The mechanism by which gas and water enter wells may be either one of movement in mass through parts of the sand containing little or no oil, or one of movement with the oil through sands containing oil with water or free gas. Production of gas or water by the first method can often be prevented by repair of the well, whereas little can be done to control these fluids if the second mechanism is responsible for their production. As high rates of flow tend to bring about commingling of free gas and water with the oil, they may cause a premature development of high gas-oil or water-oil ratios. Completion of wells should be given careful attention, and completion and repair operations should be governed by the structure of the reservoir and the condition and nature of the fluids therein. Proper consideration of these factors will result in more successful operations and in greater oil recovery from a field.

By means of specially designed apparatus which is described, oil- and gas-sand samples may be subjected to accurately measurable pressures, under which reliable quantitative determinations of absorption and permeability of the sands for certain fluids such as oil, fresh and salt water, and gases can be made. Application of absorption and permeability investigations on typical oil and gas sands to method of recovery is important.

Volume change of oil between reservoir condition and standard surface condition is called oil formation volume factor (FVF), which is very time, cost and labor intensive to determine. This study proposes an accurate, rapid and cost-effective approach for determining FVF from reservoir temperature, dissolved gas oil ratio, and specific gravity of both oil and dissolved gas. Firstly, structural risk minimization (SRM) principle of support vector regression (SVR) was employed to construct a robust model for estimating FVF from the aforementioned inputs. Subsequently, an alternating conditional expectation (ACE) was used for approximating optimal transformations of input/output data to a higher correlated data and consequently developing a sophisticated model between transformed data. Eventually, a committee machine with SVR and ACE was constructed through the use of hybrid genetic algorithm-pattern search (GA-PS). Committee machine integrates ACE and SVR models in an optimal linear combination such that makes benefit of both methods. A group of 342 data points was used for model development and a group of 219 data points was used for blind testing the constructed model. Results indicated that the committee machine performed better than individual models.

Summary This paper describes a new method, the fluid properties estimation (FPESM), that can be used at the wellsite to provide realistic predictions of PVT andphysical predictions of PVT and physical properties of the reservoir fluidduring properties of the reservoir fluid during testing. Simple and rapidmeasurements of key fluid properties and onsite compositional analysis of theproduced fluid are input data for an produced fluid are input data for anequation-of-state (EOS) -based thermodynamic model. The simulator is tunedprimarily by regression to match the measured data and is subsequently used topredict the phase behavior and PVT properties of fluids produced at reservoir, well, and produced at reservoir, well, and surface conditions. The method, which is currently applicable only to oil reservoirs, has been successfullytested in several areas of the world. Examples given compare on-site FPEpredictions with full PVT studies performed in the laboratory. performed in thelaboratory. Introduction Reservoir fluid physical property values constitute an integral part of thedata required for a comprehensive study of the reservoir and for optimal designof oil recovery and production schemes. More specifically, PVT datacorresponding to the reservoir fluid are needed to validate the well testproperly and to provide meaningful interpretation. The optimum design of thewell completion and surface facilities is possible only when the type andvolume of the possible only when the type and volume of the fluids flowingthrough the wellbore and produced through the separator are known. In producedthrough the separator are known. In addition, estimation of reservoir reservesand design of the best depletion strategy are feasible only when realistic andreasonably accurate values of the reservoir fluid properties are available.properties are available. Analysis of a representative fluid sample performedin a specialized PVT laboratory performed in a specialized PVT laboratoryoffers solutions. In most cases, however, because of backlogs and expeditionand transportation problems, the laboratory report becomes available to theoperating company several months after the well test. Meanwhile, crucialdecisions concerning planning and management of the reservoir have to be madeon the basis of physical property values. These values are currently derivedfrom empirical correlations, and the accuracy of the predictions depends on howclosely the chemical composition of the fluid being tested approaches that ofthe fluids used to derive the correlations. The quality of the PVT laboratory results depends entirely on the validityof the sample used for the analysis. The only validity check currentlyperformed on site, if any, compares only the saturation pressure of therecovered sample, measured at ambient temperature and corrected with charts tobottomhole conditions, to the reservoir's static and flowing pressure. Occasionally, the operating companies discover that the sample taken during thewell test is invalid months after the rig has been moved away. Alternative On-Site Approaches The PVT and physical property data of a reservoir fluid currently areobtained at the wellsite by prediction with empirical correlations ormeasurement with portable PVT laboratories. Rapid answers at no cost are the advantages of the first approach. Nevertheless, a considerable risk concerning the accuracy of these predictionsis taken, as the examples presented in Table 1 show. Table 1 comparesestimations for bubblepoint pressure, pb, and FVF, Bo, given by three of thepb, and FVF, Bo, given by three of the best-known correlations (Standing, Glasoand Lasater) with values measured in a PVT laboratory. Each of the five oilsused for this comparison comes from a different continent. Simple calculationsprove that underestimation of the oil FVF by 20% (not unusual when empiricalcorrelations are used) results in an overestimation of the stock-tank oiloriginally in place by the same percentage. In addition, correlations providedata that are limited to certain conditions (e.g., bubblepoint), and becausethe compositional analysis of the fluid is not considered, they fail to predictthe evolution of each property as the main reservoir parameters change duringdepletion. parameters change during depletion. The second approach, although itoffers measurements, involves considerable investment inhigh-pressure/high-temperature equipment and requires the presence ofwelltrained, experienced personnel at the wellsite. Because the PVT studyshould always be performed under perfect equilibrium conditions, several hours, if not days, of rig time are required. In addition, the weight and volumelimitations imposed on equipment transported to the rig dictate that onsite PVTequipment has a considerably reduced volume compared to that used in thelaboratory. The reduction of the sample volume inevitably leads to lessaccurate measurements. The strategy selected for development of the FPE combines features of bothapproaches. Simple measurements of key physical properties, specially selectedto characterize properties, specially selected to characterize the reservoirfluid, are performed on site with easily operated, portable equipment. Thesemeasurements are used as calibration points to tune an EOS-based simulator thatsubsequently predicts the phase behavior of the fluids at reservoir, phasebehavior of the fluids at reservoir, well, and surface conditions. P. 1046

Wax precipitation from crude oil is a major problem faced by the petroleum industry during the depletion phase from reservoirs. Reservoir oil in contact with gas tends to get enriched in very heavy fractions that may precipitate as wax under some operational conditions. In order to alleviate the problem, it is necessary to have a model that can predict the conditions under which precipitation occurs. To simulate continuous contact of the injection gas and reservoir oil, forward and backward multiple contacts are considered in this work,. The equilibrated composition of the oil samples and the injected gas is computed by material balance and flash calculations. A modified multisolid-wax model is used to study the effect of mixture composition on wax-appearance temperature. The vapor and liquid phases are described using the Peng-Robinson equation of state. It is shown that the composition variation of the oil upon methane injection has very significant effects on the wax-appearance temperature.

Hydrocarbon solvent-based enhanced oil recovery (EOR) techniques, such as vapor extraction (VAPEX) and cyclic solvent injection (CSI), have shown a great potential to recover heavy oil reserves. Solvent dissolution into heavy oil and diluted oil flow are the two main processes of these techniques. VAPEX suffers a low production rate because of the slow mass transfer and inefficient gravity drainage. Although benefited from solution gas drive and foamy oil flow, CSI is bothered with the solvent gas release and viscosity re-increase during the production period, which might seriously slow down the oil production. In this study, it is found that foamy oil flow would generate a foamy oil zone which re-saturated part of the solvent chamber. On the basis of this a phenomenon, this paper proposes a new way to enhance the CSI performance through a three-step pressure control scheme during the production period: first, reduce the model pressure to induce foamy oil flow and foamy oil zone; second, re-increase the model pressure to a preset value; third, maintain a certain pressure difference between injector and producer for gas flooding. This three-step process is called one pressure pulse and it can be consecutively repeated several times during the production period.A series of laboratory experiments have been conducted with a visual rectangular sand-packed physical model. The sandpack permeability is ∼5 Darcy. Propane is used to recover a heavy oil sample with a viscosity of 5,875 cP. Results show that (1) foamy oil could effectively re-saturate the solvent chamber; (2) more pressure pulses would lead to more oil production, while the oil production decreases with pulse number in one cycle; (3) the oil production rate of PP-CSI is 4.37 times of that of conventional CSI, and the final recovery factor of PP-CSI is 17.9% higher than that of CSI. (4) flooding-induced viscous fingering can accelerate the mass-transfer rate; meanwhile, the viscous fingering will not cause an early breakthrough of the solvent chamber.

An Alkaline-Surfactant-Polymer / Surfactant-Polymer (ASP/SP) design study generally includes intensive work. Hundreds formulations have to be tested to screen phase behavior and typically a dozen of corefloods are performed to select the best formulation and further optimize the injection strategy/slugs design to match economic criteria. To be extrapolated to the field, it is critical to perform these tests in conditions as close as possible to real reservoir conditions: reservoir temperature, injection brine, reservoir pressure and reservoir oil. Specifically, dissolved gas and high-pressure tend to significantly impact crude oil properties, and subsequently formulation behavior and performance, even when limited amount of gas is present. Ideally, this parameter should be considered from the beginning of the formulation design. However, considering the high number of tests to perform, as well as the relatively high cost and technical challenges associated with live oil experiments, it is unrealistic to routinely perform all the required experiments in high-pressure environment. We will present here the methodology developed to design surfactant based process by mimicking the impact of reservoir gas and pressure on the reservoir stock-tank oil. First a thermodynamic model based on an equation of state is fitted to reservoir PVT data (Gas/Oil Ratio or GOR, stocktank oil and associated gas composition analysis, bubble pressure and volumetric factor Bo) to predict consistent thermodynamic behavior and properties of the live oil. This step allows us to validate the reservoir conditions. A recombination of stock-tank oil with gas should be then performed to obtain the fluid in the reservoir conditions. Then we will illustrate through case studies how to combine a high-throughput robotic platform and a high-pressure/high-temperature cell to determine a representative crude oil matching live oil main properties, namely viscosity and Equivalent Alkane Carbon Number (EACN). This representative crude oil is obtained from the reservoir stock-tank oil which has been adjusted, using solvents or alkanes, to present the same characteristics as the reservoir live oil. This oil will therefore be used for an exhaustive formulation design and process optimization. Finally, we will compare oil recovery performances with the representative crude oil and with the reservoir live oil.

The results of investigations on combustion of Karazhanbas and Tengiz oil on the surface of water are presented. The minimum thickness of oil layer allowing to initiate and support the process of combustion is stated to be lie in the range of 3–5 mm. For ignition and maintenance of stable combustion of oil on water surface, a synthetic sorbent is proposed. It is found that, the synthetic sorbent accelerates the combustion process of oil on water surface threefold in comparison with the combustion process of oil without a sorbent. It is shown that the remaining mass of oil on water surface after combustion process termination, presents a bituminous substance having a good coalescence and high adhesion that allows to collect it with high efficiency by a mechanical method. The process of ignition and combustion of oil on the water surface is significantly affected by contained in it combustible volatiles. In this paper, on the example of oil from Tengiz field, the regularities of the influence of temperature and salinity on evaporation of light fractions and the burnout process are revealed. It is determined that the degree of water salinity does not affect the process of evaporation of light fractions of oil, this process is significantly affected by temperature water. The research has shown that the important factors that influence the degree of burning of the oil layer on the surface of water is the degree of salinity and the initial temperature of water, while these relationships are complex. Revealed that the salt water burning process more profitable to produce oil at water temperatures above 20 °C. The developed model in has been supplemented with a coefficient of thermal conductivity as a function depending on temperature. Numerical results more accurately predict the experimental observations. The reason is that thermal diffusivity is determined more precisely.

The gas from a well in a condensed gas deposit contains condensate and water, which must be separated from the gas, since otherwise they form crystalline hydrates that block the pipelines and equipment. Moreover, the condensate is a very valuable raw material used in industry [1]. It must be separated either by adsorption (with the aid of some adsorber) or by cooling the gas, when the heavier fractions separate out as condensate. The condensate is removed in a separator. Separation is carried out at a temperature of-g" to-15 ~ C. In the initial period of operation of the well, the gas has great excess pressure, which is expended in a throttle valve [2]. In this process the gas expands and its temperature is reduced sufficiently for the condensate to separate. However, as the deposit is used up, the natural pressure in the formation and at the well head falls, so that cooling of the gas by the throttle valve ceases to be sufficient. Therefore commercial equipment includes heat exchangers in which the hot gas from the well is cooled by cold gas from the separator. The lower the gas pressure in the formation, the greater the need to cool the gas entering the throttle valve to condense the high-boiling fractions.