О термическом повышении нефтеотдачи при добыче высоковязких нефтей и битумов для месторождений Венесуэлы

"A 2,000- to 4,000-ft-long horizontal wellcan replace several vertical wells, reducinginvestment and operational costs." Introduction Horizontal-well technology is now beingused in EOR projects, especially in thermaloil recovery. Although horizontal wells haverecently been used in miscible and water-floodprojects, the main EOR applications to dateare in steam projects. Several horizontalwells have been drilled as pilot projectsfor thermal oil recovery in bitumen andheavy-oil reservoirs. A few field pilotsshow commercial viability. Thermal oil recovery is used to produceheavy oil or bitumen in high-permeabilityreservoirs. The main advantages of the useof horizontal wells are improved sweep efficiency, enhanced producible reserves, increased steam injectivity, and a decrease inthe number of wells required for fielddevelopment. This last point is especiallyimportant in thermal oil recovery projects, where several closely spaced vertical wellsare required for economic development. A2,000- to 4,000-ft-long horizontal well canreplace several vertical wells, reducinginvestment and operational costs. The maindisadvantage of horizontal wells is theirinitial cost. Moreover, horizontal wells arecommonly completed in only one zone ata time, resulting in drainage of only onelayer. Horizontal wells have been completedin multiple zones, although not yet in thermaloil recovery applications. In bitumen reservoirs, attaining reasonableproduction rates without steaming is difficultbecause of the high oil viscosity. (Bitumenis oil with less than 10API gravity anda viscosity of more than 10,000 cp atreservoir conditions.) Steam injectivityalso can be a problem. Even with horizontalwells, initial steam cycling normally will benecessary to establish steam injectivity. Incontrast, in heavy-oil reservoirs, wells canbe produced at low rates even without steaminjection. (Heavy oil has a gravity of morethan 10API and a viscosity of less than10,000 cp at reservoir conditions.) Here, steam injection with horizontal wells isprimarily to enhance production rates, toimprove sweep efficiency, and to increaseultimate oil recovery. Injectors or Producers Horizontal wells can be used as injectors orproducers. The large contact area ofhorizontal wells can enhance injection ratesin injection wells and improve productionrates in producing wells. When horizontal wells are used as producers, they providea large producing capacity with highproduction rates. Hence, high steam injectionrates in surrounding injection wells arenecessary to maintain reservoir pressure. Whenhorizontal wells are used as injectors, theninjecting steam uniformly along the well length occasionally may be difficult, espeially during the initial steam-injection period. This is because steam condensation ina cold horizontal well reduces the welllength available for steam injection. Thisproblem can be reduced or eliminated bypreheating a long horizontal wellbore beforesteam injection. In field applications, excluding cyclicsteam stimulation, horizontal wells are usedmore often as producers than as injectors. In horizontal producers, at least initiallybefore the heat front arrives and the entire wellbore is heated, only cold heavy oil maybe produced. The pressure drop in the longwellbore can be significant because of thehigh viscosity of the cold oil, which maycause uneven production along the welllength. Recovery Process Concepts Horizontal wells provide flexibility indeveloping well patterns for enhancing theweep efficiency of thermal oil recovery. Itpossible to drill a long horizontal well, or to re-enter an existing vertical well and drill short drainholes 100 to 300 ft long)to enhance steam injectivity and/or oilproductivity. This procedure can beespeially useful in multilayered reservoirswhere a specific zone can be developed witha minimum number of vertical wells. In multilayered heavy-oil reservoirs, suchis those in South America, production insome zones is delayed because of theunavailability of producing wells. In thesemultilayered reservoirs, the number of wells required to drain several zonessimultaneously is too large. JPT P. 1302⁁

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 236–244. Abstract Results of a field research project on the thermal recovery of oil by movement of a combustion front are presented. This field test was conducted in the South Belridge field, Calif. The test pattern was a single 2.5-acre five-spot pattern in the 700-ft deep Tulare sand. Results of this project indicate the technical feasibility of producing high viscosity, low-gravity crude oils by thermal means. It was demonstrated that heavy oils could be moved rapidly over considerable distances by thermal drive, and that high percentage recoveries of oil could be effected. The bulk of the oil recovery came after arrival of the burning front at a production well. However, rapid corrosion and high-temperature failure of conventional pipe and equipment both below and above surface occurred. Stainless steels gave more satisfactory performance under these conditions than did conventional steels. Oxygen was seldom observed in gas from wells ahead of the burning front, and it appears that the front was continuous throughout the life of the experiment. Introduction During late 1953 and early 1954, industry-wide attention was focused on the thermal recovery of oil by movement of a combustion front through an oil zone. Two separate Oklahoma field tests were described in publications by. Kuhn and Koch, and Grant and Szasz. To obtain basic information needed for making engineering and economic appraisals of commercial recovery of heavy oil by this thermal recovery method, a new field research project was started May 31, 1955. Twelve oil companies contributed to this project with General Petroleum Corp. as operator. Since combustion recovery experiments with heavy oils in other areas had been conducted In small patterns, an important purpose of this test was to determine whether the process could be operated in a pattern of near-commercial well spacing. The South Belridge field, located 30 miles north of Taft, Calif., was chosen because its oil sands are similar to many heavy oil sands which typically have low primary recovery and leave a large amount of oil in place. Such fields are not particularly suited for common secondary recovery methods.

Insights into heat transport for thermal oil recovery

Even though thermal oil recovery methods already contribute about 80% of oil production from all known EOR methods, oil production by thermal recovery 1s expected to continue to increase for at least 10 years and to provide the highest contribution to all recovery of all other EOR methods for at least 20 years into the future. Under a somewhat more optimistic scenario, oil production from thermal recovery would grow for about 20 years and would continue to produce more oil than any other EOR method for more than 30 years into the future. Thermal oil recovery potential in terms of production rates and ultimate recovery for various technical and economic scenarios are presented in graphical form for the next 30 years. Introduction The subject study an Enhanced Oil Recovery was prepared by the National Petroleum Council (NPC), in response to a request by the Secretary of the U.S. Department of Energy. NPC is a board of industry leaders established solely for the purpose of advising, informing and making recommendations to the Secretary of the U.S. Department of Energy on any matter relating to the petroleum industry. Eighty-six persons from thirty-four companies and several Department of Energy representatives worked over a period of seventeen months to develop a document which provides an in-depth study of the EOR potential for the next 30 years under various technical and economic scenarios. To accomplish this task, the Coordinating Subcommittee established four task forces which specialized in Chemical, Miscible and Thermal recovery processes, as well as in Costs and Economics of EOR. Each of these subjects are treated separately and additional important information is attached in appendices to the final report. The appendices also cover environmental considerations, research progress and future research needs for each technology. ASSUMPTIONS AND METHODOLOGY This study began with the development and verification of a representative data base of reservoirs in the United States. Then, screening criteria were defined in order to determine which reservoirs might be amenable for each process. Then, specially developed simplified predictive models were used to predict performance and calculate economics. Incidentally, these predtct1ve models are now being documented and will soon be available to the public. Reservoirs were then assigned to that process which was economic and recovered the most oil. Results were combined by calendar year into projections of rate and ultimate recovery for the various technology cases, prices and rates of return. Finally, results were analyzed, reviewed, and, where necessary, re-determined. Developing the data base proved to be a formidable task. Data from several sources, including that from the Department of Energy were subjected to rigorous industry review and enhancement. This resulted in a data base of over 2500 reservoirs containing 355 billion barrels of oil originally in place. This represents over 70% of the discovered oil in the United States. It has been discovered that, by eliminating reservoirs containing less than 50 million barrels of oil originally in place, as many as 65% of the reservoirs to be studied could be eliminated.

This paper describes the development of a fully implicit general thermal model (ISCOM) for simulating in situ combustion or steam processes. The model includes four phases, a variable number of oil components, a variable number of chemical reactions, gravity and capillary pressure terms, and the possibility of modeling emulsions. The finite-difference formulation of ISCOM operates in one, two or three dimensions and contains implicit and sequential implicit solution techniques as options. It is highly stable, averaging 30% saturation or molar fraction changes during each time step. The model includes the use of pseudo-phase equilibrium ratios which allows a single formulation, even though phases may disappear. The computer program was designed to emphasize clarity and to program was designed to emphasize clarity and to optimize storage. The matrix solution technique is a modified form of Gaussian elimination. The variables and fundamental equations have been aligned so that pivoting for numerical stability is not necessary. pivoting for numerical stability is not necessary. Other special features include Newtonian iteration with numerically calculated derivatives, embedding of the coke equation, two-point upstream and harmonic mobilities as options to reduce truncation error and the grid orientation effect, and an automatic time step selector. Results are presented showing the sensitivity to changes in number of grid blocks and time step size and showing the influence of harmonic weighting on the grid orientation effect. Introduction Thermal methods occupy a prominent position in the recovery of low API crudes. The processes taking place during thermal oil recovery are of a complex place during thermal oil recovery are of a complex nature. Experience has shown that in order to model such processes, any numerical simulator must be extremely stable to produce practical results. The trend, therefore, has been towards increasing degrees of implicitness in the construction of such simulators. This demands, however, the utilization of large computer storage and run times, especially for multi-dimensional problems. This paper describes the development of a fully implicit, finite-difference, general purpose thermal simulator (ISCOM) for modeling in situ combustion and steam processes. The storage and computation time problems have been resolved by the development of a problems have been resolved by the development of a special matrix hand reducing option. Another feature of thermal recovery simulations in heavy oils is the severity of the grid orientation effect. In ISCOM this effect is alleviated by an option which introduces harmonic mobility weighting. The steam drive/soak options are subsets of the in situ combustion model, whereby unnecessary reactions and equations are removed. The steam versions are described here only briefly. Therefore this paper concentrates primarily on the in situ combustion option. The formulation of the model, physical property package, and method of solution will be described, package, and method of solution will be described, together with the results of some test calculations. FORMULATION OF THE MODEL Basic Assumptions The mathematical model is based on the following assumptions:The model can operate in one, two or three dimensions with variable grid spacing.The number of components is variable, and components are distributed among four phases: water (w), oil (o), gas (g), and solid (c).Water and oil components may be present in both oil and water phases, allowing for an approximate treatment of emulsions.The number and type of chemical reactions is variable.

In this article, the importance of colloids and interfaces in thermal heavy oil or bitumen extraction methods is reviewed, with particular relevance to oil sands. It begins with a brief introduction to the chemical composition and surface chemistry of oil sands, as well as steam-based thermal recovery methods. This is followed by the specific consideration of steam-assisted gravity drainage (SAGD) from the perspective of the interfacial chemistry involved and factors responsible for the displacement of bitumen from reservoir mineral surfaces. Finally, the roles of the different chemical additives proposed to improve thermal recovery are considered in terms of their contributions to recovery mechanisms from interfacial and colloidal perspectives. Where appropriate, unpublished results from the author’s laboratory have been used to illustrate the discussions.

Heavy oil is one of the most useful energy resources specially in the times of crises when other resources are not present in profusion. However, Occurrence of heavy oil in unconsolidated sands is one the most challenging factor to recover the heavy oil. Therefore, in this study the main focus is derived towards the extraction of heavy oil with optimistic procedure called air injection. For the research, a reactor assembly was developed for the experimental work on air (21% oxygen) injection into heavy oil (12.59 °API) reservoir. Total 13 kinetics runs were conducted on unconsolidated cores by varying the parameters involved system pressure, flow rate (air flux), oxidation temperature (heat input), and rock formation (sand matrix). It was found that the process is very dependent on operating conditions employed, as oxygen consumption rate was very dependent on air flux. Increase of air flux from 15.19 to 22.78 m3/m2-hr resulted in slightly increasing rates of oxygen consumption over the temperature range under investigation. The temperature difference also shows great effect on the high temperature oxidation. The pressure and porous media also have great impact on the combustion behavior. The influence of individual parameter was obtained from analysis of the inlet oxygen and composition of flue gases from the combustion cell. Indeed, the oxygen conversion was too less to evaluate the kinetic data at temperature less than 250 °C while for oxidation reactions, the oxygen statistics analyzed from temperature above than 350 °C. The experimental results reveal that the average maximum peak temperature was 440 °C, and the oxidation reaction process at high temperature was very effective in terms of produced carbon oxides with an average percentage of 9.5% CO2, 5.5% CO in flue gases. Oil displacement was observed from the analysis of flue gases, consequently; incremental oil recovery was achieved between 56%-80% under high temperature oxidation (HTO) conditions.

The majority of global petroleum is in the form of highly viscous heavy oil. Traditionally heavy oil in sands at shallow depths is accessed by large scale mining activities. Recently steam has been used to allow heavy oil extraction with greatly reduced surface disturbance. However, in situ thermal recovery processes can generate hydrogen sulphide, high levels of which are toxic to humans and corrosive to equipment. Avoiding hydrogen sulphide production is the best possible mitigation strategy. Here we use laboratory aquathermolysis to reproduce conditions that may be experienced during thermal extraction. The results indicate that hydrogen sulphide generation occurs within a specific temperature and pressure window and corresponds to chemical and physical changes in the oil. Asphaltenes are identified as the major source of sulphur. Our findings reveal that for high sulphur heavy oils, the generation of hydrogen sulphide during steam assisted thermal recovery is minimal if temperature and pressure are maintained within specific criteria. This strict pressure and temperature dependence of hydrogen sulphide release can allow access to the world's most voluminous oil deposits without generating excessive amounts of this unwanted gas product.

Chapter FOUR - In-situ thermal heavy oil recovery

With easy oil recovered all across the world, the oil fields are depleting and extraction of heavy oil is becoming more important. The exploration and drilling of new fields is expensive and time intensive. With most of the oil remaining is heavy and viscous; Enhanced Oil Recovery (EOR) methods are followed. Thermal EOR is the most widely used method in which steam injection is the most popular. Every year natural gas is burnt to produce steam and this amount is increasing as heavy oil reserves are developing all across the world. With increase in technological advancements and goal of reducing carbon emissions, solar energy is used to produce steam for the injection. This technology is called solar wells. The main objective is highlighting the cost of steam produced by natural gas and solar wells and finding investment, installation, operation and maintenance costs of these generators. Further, analyzing these costs, recommendations are made if new technology (solar wells) is worth the investment.

This paper includes a review of horizontal well field histories and applications around the globe, with special emphasis on South and Latin American applications. The paper includes descriptions of economically successful, as well as unsuccessful horizontal wells in field applications. Results of the field histories are used to summarize essential parameters for economic success. Horizontal wells have been used in: 1) thin pay zones, 2) naturally fractured reservoirs, 3) formations with gas and water coning problems, 4) heavy oil reservoirs, 5) gas reservoirs, and 6) enhanced oil recovery (waterflood applications, miscible floods, and thermal oil recovery). Out of about 2500 horizontal wells drilled worldwide, almost 75% are drilled in the USA and Canada. In addition, most of the U.S. welts are drilled in a few formations, namely, Austin Chalk and Bakken Shale. Host of the U.S. applications are in low permeability (*1 md) reservoirs. Outside the U.S., the majority of applications are for gas and water coning, mainly for water coning. These applications are in high permeability (400 md to 10 Darcy) reservoirs. In general, horizontal wells have a higher success rate in water coning applications than in gas coning situations. Recently, horizontal wells have also been used in secondary recovery applications. Horizontal wells have exhibited excellent results in miscible CO2 floods. While application of horizontal wells in waterflooding shows great potential, application in thermal oil recovery shows mixed economic results. The key parameters for success, based upon field results, appear to be: 1) fracture intensity, 2) hydrocarbon pay zone thickness, 3) well spacing, 4) vertical coomunication, 5) formation damage and post drilling clean-up ability, 6) geological control, 7) multiwell prospect, and 8) cooperation in geological, reservoir, drilling, and completion departments.

Dynamic optimization of thermodynamically rigorous models of multiphase flow in porous subsurface oil reservoirs

Light hydrocarbon gases such as methane, ethane, propane, and butane or other so called gaseous solvents have been suggested as steam additives to improve bitumen recovery and energy efficiency. The water content of these gases is one of the key requirements in the simulation and design of solvent‐aided thermal heavy oil recovery processes. In this work, we present new experimental data for the water content of these gases at high temperatures (up to 493.15 K) and moderate pressures (P < 6 MPa). The experimental data was regenerated using the cubic‐plus‐association equation of state. The Soave–Redlich–Kwong equation of state is used to treat the physical interactions. The association interactions are captured using Wertheim's first‐order thermodynamic perturbation theory. A set of binary interaction parameters is proposed to calculate the water content of methane, ethane, propane, and n‐butane at the operating conditions of the thermal heavy oil and bitumen recovery processes. © 2016 American Institute of Chemical Engineers AIChE J, 63: 1384–1389, 2017

The dynamics of Mn(H 2O) 2+6 complexes in Ca-montmorillonite in the temperature interval typical for in-situ recovery processes

Steam assisted gravity drainage (SAGD) is an effective thermal recovery method for heavy oil reservoirs. Mudstone interlayers with low-permeability may block the expansion of the steam chamber and then reduce the SAGD thermal recovery. However, the mudstone may be thermally fractured by the coupling effects of thermal-hydro-mechanical (THM) in the SAGD production process. In this study, taking a heavy oil reservoir in Xinjiang as an example, we studied the thermal cracks’ initiation of mudstone interlayer by numerical simulation. Results show that: (1) Temperature changes are the main factor of affecting mudstone’s fracturing or crack propagation, and the effects of mudstone interlayer’s thickness are slightly. (2) With larger Young’s modulus, the critical fracturing temperature is lower. (3) In the peak period of gravity drainage, along the horizontal well, most of the mudstone interlayers reach the fracturing critical value and produce thermal cracks. The existence of thermal cracks will improve the SAGD productivity.