Carbon Dioxide Flooding Research Articles

Asphaltene aggregation in organic solvents

Asphaltenic solids formed in the Rangely field in the course of a carbon dioxide flood and heptane insolubles in the oil from the same field were used in this study. Four different solvents were used to dissolve the asphaltenes. Near-infrared (NIR) spectroscopy was used to determine the onset of asphaltene precipitation by heptane titration. When the onset values were plotted versus asphaltene concentrations, distinct break points (called critical aggregation concentrations (CAC) in this paper) were observed. CACs for the field asphaltenes dissolved in toluene, trichloroethylene, tetrahydrofuran, and pyridine occurred at concentrations of 3.0, 3.7, 5.0, and 8.2 g/l, respectively. CACs are observed at similar concentrations as critical micelle concentrations (CMC) for the asphaltenes in the solvents employed and can be interpreted to be the points at which rates of asphaltene aggregations change. CMC values of asphaltenes determined from surface tension measurements (in pyridine and TCE) were slightly higher than the CAC values measured by NIR onset measurements. The CAC for heptane-insoluble asphaltenes in toluene was 3.1 g/l. Thermal gravimetric analysis (TGA) and elemental compositions of the two asphaltenes showed that the H/C ratio of the heptane-insoluble asphaltenes was higher and molecular weight (measured by vapor pressure osmometry) was lower.

Carbon Dioxide Flooding: A Classroom Case Study Derived from Surgical Practice

The surgical opening in open-heart surgery is often flooded with carbon dioxide gas to avoid air embolisms when the heart is closed and restarted. This practice can be used in chemistry courses to illustrate concepts of gas density, solubility, and acid–base equilibria, including buffering.

Stroke in surgery of the thoracic aorta: Incidence, impact, etiology, and prevention

Objectives: To determine the incidence, impact, etiology, and methods for prevention of stroke after surgery of the thoracic aorta. Methods: A total of 317 thoracic aortic operations on 303 patients (194 male, 109 female) aged 13 to 87 years (mean 61 years) were reviewed. There were 218 procedures on the ascending aorta and arch and 99 on the descending aorta. Of the 218 procedures on the ascending aorta and arch, 86 involved cardiopulmonary bypass, 122 involved deep hypothermic circulatory arrest, 2 involved antegrade cerebral perfusion, and 8 involved “clamp and sew” or left heart bypass. Of the 99 procedures on the descending aorta, 20 involved “clamp and sew,” 69 involved left heart or full bypass, and 10 involved deep hypothermic circulatory arrest. A total of 206 cases were elective and 97 were emergency operations. Results: Twenty-three (7.3%) of 317 patients had a stroke. Fifteen strokes occurred in operations on the ascending aorta and 8 in operations on the descending aorta (6.9% vs 8.1%; P =.703). Stroke occurred in 16 (16.5%) of 97 emergency operations and 7 (3.4%) of 206 elective operations (P =.001). In the 300 patients surviving the operation, stroke was a significant predictor of postoperative death (9/23 [39.1%] vs 23/277 [8.3%]; P =.001). Analysis of operative reports, brain images, and neurologic consultations revealed 15 of the 23 strokes were embolic, 3 were ischemic, 3 hemorrhagic, and 2 indeterminate. Patients with stroke had longer intensive care unit stays (18.4 vs 6.8 days; P =.0001), longer times to extubation (12.7 vs 3.8 days; P ||.0012), longer postoperative stays (31.4 vs 14.3 days; P =.001), and decreased age-adjusted survival (relative risk 2.775; P =.0013). After implementation of a rigorous antiembolic regimen, both strokes and mortality trended downward. Conclusions: (1) Stroke complicates surgery of both the ascending and descending thoracic aorta and warrants consideration in decision making. (2) Strokes are largely embolic. (3) Antiembolic measures for particles and air are essential, including gentle aortic manipulation, thorough debridement, transesophageal echocardiography to identify aortic atheromas, carbon dioxide flooding of the field, and (in descending cases) proximal clamp application before initiating femoral perfusion.J Thorac Cardiovasc Surg 2001;122:935-45

ECONOMIC OPTIMIZATION OF EOR PROCESSES USING KNOWLEDGE-BASED SYSTEM: CASE STUDIES

The main challenge of Enhanced Oil Recovery (EOR) processes at the prevailing low oil prices is to reduce the cost. An optimization methodology, combined with an economic model, is implemented into an expert system for optimizing the net present value of full field development with an EOR process. The approach is automated and combines an economic package and existing numerical reservoir simulators to optimize the design of a selected EOR process using sensitivity analysis. The EOR expert system includes three stages of consultations: (1) select an appropriate EOR process on the basis of the reservoir characteristics, (2) prepare appropriate input data sets to design the selected EOR process using existing numerical simulators, and (3) apply the discounted-cash-flow methods to the optimization of the selected EOR process to find out under what conditions at current oil prices this EOR process might be profitable. The project profitability measures were used as the decision-making variables in an iterative approach to optimize the design of the EOR process. The economic analysis is based on the estimated recovery, residual oil in-place, oil price, and operating costs. Two case studies are presented for two reservoirs that have already been produced to their economic limits and are potential candidates for surfactant/polymer flooding, and carbon-dioxide flooding, respectively, or otherwise subject to abandonment. The effect of several design parameters on the project profitability of these EOR processes was investigated.

Time-lapse monitoring of immiscible fluid-flow models

Physical fluid-flow models aid understanding of hydrocarbon movement through water-saturated sediments because they provide real data that do not rely on assumptions and are therefore useful to validate numerical reservoir simulations or to study processes for which the mathematical formulations are not well defined. Such models can have applications in geology for studying mechanisms of secondary oil migration (Thomas and Clouse, 1995), or in reservoir engineering to evaluate enhanced oil recovery methods such as steam injection (Frauenfeld et al., 1994) and carbon dioxide floods (Tuzunoglu and Bagci, 2000).

Antelope shale (Monterey Formation), Buena Vista Hills field: Advanced reservoir characterization to evaluate CO2 injection for enhanced oil recovery

Very large volumes of oil in developed siliceous shale reservoirs of the southern San Joaquin basin, California, may be recoverable through carbon dioxide (CO2) flooding. More than 7 billion bbl of oil, trapped in the Miocene Monterey Formation, are present at relatively shallow depths in a series of large and giant fields discovered during the early part of the 20th century yet that have typical recoveries of less than 6%. Such low recoveries are due to the unique nature of the reservoir and to early completion practices. Siliceous shales consist mainly of biogenic silica (original diatom frustules) and varying amounts of clay and silt/sand. These rocks are thinly laminated and typified by high porosities (> 30%), very low permeabilities (< 1 md), extremely small pore throats, and variable degrees of fracturing. Early well completions, up through the 1950s, employed slotted liners and commingled production at high rates, thereby preventing interval evaluation and also causing rapid loss of reservoir pressure. To better understand these reservoirs, and to establish baseline criteria for evaluating CO2 flooding as an option for enhanced recovery, a multiyear study sponsored by the U.S. Department of Energy and Chevron U.S.A. was performed in Buena Vista Hills field, focused on the Antelope shale zone (upper Monterey Formation). A combination of advanced reservoir characterization, three-dimensional earth modeling, and flow simulation was performed. Resulting data provide essential new insight into the detailed nature of these reservoirs, for which mostly vintage (Begin page 562) log data (pre-1966) was previously available. Criteria established for CO2 flood evaluation include current oil saturation levels, reservoir pressure, lithologic heterogeneity, degree of fracturing, and well spacing. On the basis of these criteria, a site was chosen for a CO2 pilot test in Lost Hills field. This pilot is encompassed within the present Chevron-DOE study and will be covered in a future E & P Notes article.

A study on the measurement for forest ecological benefit

The indexes of dependent variables of the measurement on the forest ecological benefits were defined according to the analysis of the multiple ecological benefits of forest. This indexes system includes watereserving, soil and water conservation, wind and sand suppression, microclimate improvement, carbon dioxide assimilation, atmosphere purification, flood and drought mitigation, tourism resource and wild creature protection benefits. The main factors from the numerous factors that affect dependent variables were chosen as independent variables. At last, a multivariate linear model was established for measurement of forest ecological benefit. With this multivariate linear model the forest ecological benefit of China was calculated. The forest ecological benefit of China is 723816 million yuan per year, which equals to 23.07% of the gross domestic product of China.

Delaware Mountain Group, West Texas and Southeastern New Mexico, A Case of Refound Opportunity: Part 1--Brushy Canyon

Exploration in Permian (Guadalupian) deep-water sandstones of the Delaware Mountain Group, west Texas and southeast New Mexico, represents a success story of the 1990s derived from reevaluation of reservoirs previously deemed uneconomical. Recent discoveries have concentrated on the Brushy Canyon in New Mexico and, to a lesser extent, the Cherry Canyon in Texas. Brushy Canyon reservoirs in particular previously were overlooked due to indications of poor reservoir quality from log and well test data; however, oil shows observed on mud logs across the northern Delaware basin led to new completion efforts in the late 1980s and 1990s using gel-sand fracture stimulations. Productive reservoirs are very fine to fine-grained arkosic to subarkosic sandstones with porosities of 12-25% and permeabilities typically of 1-5 md. Better reservoir quality is concentrated in massive channel sandstones variably interpreted as deposited by turbidity or saline density currents. Significant clay content, lamination, and close interbedding between oil- and water-bearing units make log analysis and reserve estimates problematic. As a result, the mud log remains the cheapest, most practical indicator of pay. Reservoir sandstones can be divided into a series of major productive trends related to proximal/slope and more distal/basin-floor depositional settings. Well productivity is variable within each trend, but primary recovery rarely exceeds 10%. Options for enhanced recovery include pressure maintenance, waterflooding, and carbon dioxide flooding. Early indications suggest that carbon dioxide flooding may be most appropriate in these low-permeability, clay-bearing reservoirs.

Abstract: Mule Field in the Paradox Basin of Southeastern Utah: A Case Study for Small Carbonate Buildups, Horizontal Drilling, and Carbon Dioxide Flooding&amp;nbsp;

Abstract: Mule Field in the Paradox Basin of Southeastern Utah: A Case Study for Small Carbonate Buildups, Horizontal Drilling, and Carbon Dioxide Flooding&amp;nbsp;

Some Applications of Fractal Mathematics In the Evaluation of Environmental Problems

Abstract Recent advances in the development of the techniques of fractal mathematics permit applications to environmental problems commonly encountered in the petroleum industry and other industries. Examples are given whereby the use of Turcotte's theory of renormalization groups leads, to simple equations for 'use in the interpretation of data sets and in practical decision making. Specifically; the applications are illustrated, by examples. Mercury contamination data at a gas plant are interpreted and the optimal volume of soil excavation is determined at a contaminated site. Introduction The relatively new theories of fractal mathematics were introduced as recently as 1967 by Manctelbrot(1). He noticed that the apparent or measured length of a complex coastline increased with the decreasing length, of the measuring rod, in accordance with a power law Equation (Available in full paper) where P is the length of the coastline, and r is the length of the measuring rod. The term D in the exponent is referred to as the fractal dimension. Since Mandelbrot's initial work, many natural phenomena have been shown to have fractal properties. Applications have been published in petroleum engineering by: Hewett in investigating the effect of reservoir heterogeneities on a water flood(2), by Tang et al., as a means of forecasting the performance of carbon dioxide and water floods(3), and by the present authors in reserve estimation of hydrocarbon(4). Maloy et al., have analysed the viscous fingers in two-dimensional fluid flow in porous media and have demonstrated fractal properties(5). In heterogeneous catalysis, it was realized that the molecular accessibility of a rough catalyst surface is dependent of molecular size, and an equation of the type Equation (Available in full paper) is obeyed, where N is the number of molecules needed for monolayer coverage, S is the molecular size, and Da is the fractal dimension of the surface available for coverage. A short review of this subject has recently been published by Avnir(6). In addition to the practical engineering applications, Turcotte has applied the theory to geology and geophysics(7), and it is these applications which are considered here for the solution to environmental problems. Turcotte shows that the cumulative average weight grade of an ore, Equation(1)(Available in full paper) Equation(2) (Available in full paper) Equation(3) (Available in full paper) The derivations may be found in Reference (6). Turcotte illustrated these equations by considering the total tonnage and grades of mercury ore mined in the United States. He obtained a fractal dimension of D =2.01. On extrapolation, by setting Mo equal to the tonnage of soil in the United States and arbitrarily choosing a data pair from the line, he obtained a value of Co = 80 ppb. This value is the same as the generally accepted mean concentration of mercury in U.S. soils, as required. Applications Case 1: Mercury Contamination at a Gas Plant At a sour gas plant in Southern Alberta, which is currently being decommissioned, a limited number of soil samples were analysed for the presence of mercury.

Field Test of Immiscible CO2 Drive in Daqing Oil Field

Abstract The choice of water alternate carbon dioxide flooding in Sanan was decided based on prefeasibility studies on EOR methods suitable for Putaohua reservoir in Sanan area of Daqing Oil Field. This process was first implemented on one pilot, before any industrial extension. This paper introduces the pilot test, evaluates the effects of CO2 drive and analyzes behavioral characteristics of the test.

Mechanistic Study Of Carbon Dioxide Flooding Using Horizontal Wells

Abstract A finite-difference, equation-of-state, compositional simulator has been used to conduct a mechanistic study of carbon dioxide flooding using horizontal wells. We have used the reservoir and fluid properties of an actual West Texas carbonate reservoir that is currently being waterflooded. The phase behaviour and properties of the CO2 used in these simulations are typical of those of multiple-contact-miscible (MCM) field conditions of West Texas. Although the equation-of-state MCM calculations require much more computer time, comparison with a first-contact- miscibility (FCM) displacement demonstrates the importance of the more realistic phase behaviour description since the injectivity and oil recovery were significantly different for the MCM than for the FCM simulations. All simulations were conducted using permeability fields that have been conditioned with core data taken from two wells in the field. We have compared the performance of the process using a vertical injector and a vertical producer with that using a horizontal injector and a vertical producer combination. We have also investigated the impact of CO2 slug size, skin factor, and relative permeability parameters. These studies show significant sensitivity of the tertiary injectivity of CO2 and brine to the wellbore skin factor and to relative permeability. In tight reservoirs such as that considered in this study, injectivity has a major impact on the efficiency of the process. Although the oil recovery after a given number of injected pore volumes is relatively insensitive to many of the variables investigated in this and earlier studies, the oil recovery at a fixed time such as 20 years varies tremendously since it is limited by the amount of CO2 that can be injected in this time period. This study adds significant new insights and conclusions about the feasibility of using CO2 with horizontal wells. Introduction During the last 15 years, the petroleum industry has experienced a rapid increase in the number of horizontal wells being drilled and completed because recent advances in drilling technology have resulted in substantially reduced drilling and completion costs of horizontal wells(l). Drilling cost figures compiled by Joshi(2) showed that horizontal well costs have declined from about six to eight times that of vertical well costs to about two to three times. In some cases where extensive drilling experience has been acquired, the costs of drilling horizontal wells are reported to be about the same or even lower than vertical well costs(3). Another factor contributing to the upsurge in horizontal well activity is the fact that horizontal wells can deliver two to ten times the performance of conventional wells, mainly because of their larger surface areas exposed to flow(l). Finally, horizontal wells offer solutions to the problem of producing oil or gas in reservoirs where conventional technology either fails or is uneconomic. Some examples are(l):reservoirs where conventional wells have low productivity,reservoirs with vertical fractures,oil reservoirs where recovery is limited by water or gas coning, and (4) thick continuous heavy oil and bitumen reservoirs where steam-assisted gravity drainage is practical.

High‐resolution crosswell imaging of a west Texas carbonate reservoir: Part 1—Project summary and interpretation

A carbon dioxide flood pilot is being conducted in a section of Chevron’s McElroy field in Crane County, west Texas. Prior to [Formula: see text] injection, two high‐frequency crosswell seismic profiles were recorded to investigate the use of seismic profiling for high‐resolution reservoir delineation and [Formula: see text] monitoring. These preinjection profiles provide the baseline for time‐lapse monitoring. Profile #1 was recorded between an injector well and an offset observation well at a nominal well‐to‐well distance of 184 ft (56 m). Profile #2 was recorded between a producing well and the observation well at a nominal distance of 600 ft (183 m). The combination of traveltime tomography and stacked CDP reflection amplitudes demonstrates how high‐frequency crosswell seismic data can be used to image both large and small scale heterogeneity between wells: Transmission traveltime tomography is used to image the large scale velocity variations; CDP reflection imaging is then used to image smaller scale impedance heterogeneities. The resolution capability of crosswell data is clearly illustrated by an image of the Grayburg‐San Andres angular unconformity, seen in both the P‐wave and S‐wave velocity tomograms and the reflection images. In addition to the imaging study, cores from an observation well were analyzed to support interpretation of the crosswell images and assess the feasibility of monitoring changes in [Formula: see text] saturation. The results of this integrated study demonstrate (1) the use of crosswell seismic profiling to produce a high‐resolution reservoir delineation and (2) the possibility for successful monitoring of [Formula: see text] in carbonate reservoirs. The crosswell data were acquired with a piezoelectric source and a multilevel hydrophone array. Both profiles, nearly 80 000 seismic traces, were recorded in approximately 80 hours using a new acquisition technique of shooting on‐the‐fly. This paper presents the overall project summary and interpretation of the results from the near‐offset profile.

Ranking Reservoirs for Carbon Dioxide Flooding Processes

SUMMARY The screening of large number of reservoirs for the application of EOR processes has been generally done through "rules of thumb" which oftentimes fail to identify the most suitable reservoirs, due to their binary characteristics, which do not take into account synergistic effects on process performance. Therefore, a new screening method is developed in this work to rank reservoirs for carbon dioxide flooding which attempts to solve this shortcoming. The method is based on a parametric study, carried out systematically to determine the effect of reservoir properties on reservoir response to the gas injection. The study was done using a fully compositional simulator, a black oil model with a mixing parameter, and a semi-analytical predictive model. Results obtained with the three simulators are presented and compared in this paper. Reservoir parameters examined were temperature, pressure, porosity, permeability, dip, API gravity, oil saturation, net oil sand thickness, minimum miscibility pressure, saturation pressure, remaining oil in place, and reservoir depth. The optimum set of parameters which gave the best average oil production rate for a base case was obtained from the simulation studies. The base case consisted of the injection of 2000 MSCF/D of carbon dioxide in a inverted five spot, 40 acres pattern. The decrease in oil production rate with departures of the characteristic parameters from the optimum values were also determined to quantify the importance or weight of each property. Actual reservoirs were ranked by an arbitrary heuristic function, called the exponentially varying function, whose value depended exponentially on the weighted differences between the properties, characteristic of the reservoir, and the optimum values obtained from the simulation studies. Results obtained with the three simulators compare quite well and indicate that on the average, the best reservoir for carbon dioxide injection should have an oil gravity of 36°API, a temperature of 150 °F, a permeability of 300 mD, an oil saturation at the start of the injection of 60%, a reservoir pressure at the time of injection of around 200 psi over minimum miscibility pressure, a porosity of 20%, a net sand thickness of 40 ft and a reservoir dip of 20°. Of the above parameters, those whose changes around the optimum influence the most process performance are API gravity, oil saturation and reservoir pressure. Therefore, the reservoirs with these three parameters closer to the optimum values are the best candidates for CO2 injection. This is taken adequately by the exponentially varying function defined in the paper. The procedure was applied to rank about six hundred reservoirs in the greater Anaco and Oficina areas of Eastern Venezuela in order to identify the most suitables for a pilot test. The reservoir ranked 30th by the method hereby described was chosen to implement the pilot. This procedure could be easily extended to other EOR processes once the necessary simulations are carried out.

Three-phase gas/oil/brine relative permeabilities measured under carbon dioxide flooding conditions : Dria, D E; Pope, G A; Sepehrnoori, K SPE Reservoir EngngV8, N2, May 1993, P143–150

Three-phase gas/oil/brine relative permeabilities measured under carbon dioxide flooding conditions : Dria, D E; Pope, G A; Sepehrnoori, K SPE Reservoir EngngV8, N2, May 1993, P143–150

The Application of Fractal Geostatistics to Oil And Gas Property Evaluation And Reserve Estimates

Abstract A fractal is a geometrical object which seems to have similarshapes when observed at different ranges of scales. For example natural fractures in a reservoir, permeability data, porosity data and the viscous fingers resulting from unstable miscible flood have been found to demonstrate such fractal characteristics. Turcotte introduced the concept of renormalization group and derived the fractal dimension for the fragmentation of a cubic cell into subsequent elements with decreasing volume. This concept has been successfully applied to analyse the tonnage and grade relationship using the production dam from the mining of minerals. In this study, the concept of renormalization group has been extended to predict the discovery rate of oil and gas pools, which is based on the success history of exploration drilling in a certain region. As a secondary objective, a model for predicting the ultimate reserve in a petroleum bearing region has also been developed. Introduction It has long been recognized that many processes in nature demonstrate fractal characteristics. The concept of fractal geometry provides a means of quantifying these processes. Basically, a power law relationship between number and size defines a fractal. The classic example of a fractal is the measured length of a complex coastline. If the length L(t) of the coastline is related to the length of the measuring stick, r, by: Equation (1) (Available in full paper) then the coastline is a fractal and D is the fractal dimension. The application of fractal geometry to the petroleum problems is not new. Hewett (1) applied the techniques of fractal geostatistics and conditional simulation to investigate the effect of reservoir heterogeneity on waterflood. Tang et. al. (2) applied the same techniques to forecast the performances of waterflood and carbon dioxide flood processes in a low permeability sandstone reservoir characterized by alternating sand/shale sequences. Multiphase flow in a porous media also demonstrates fractal characteristics. Displacement of a fluid in porous media by another fluid of a much lower viscosity usually results in a displacement front which is notoriously unstable with the development of a so called viscous fingers. Maloy et al (3) analysed the viscous lingers in two-dimensional fluid flow in a porous media and found that the viscous lingers for various viscosity ratios generally have a fractal dimension of about 1.6. The objective of this study was to extend the techniques of fractal geostatistics to oil and gas property evaluation and reserve estimates. We will begin with a review of the conventional methods for forecasting the ultimate reserves and discovery rates of oil and gas exploration. A reliable estimate of the amount of oil and gas in a geographic area would be of great value in formulating governmental and corporate policies. The term "reserve" used in this paper means the probable amount of petroleum deposits in a geologic region based on exploration drilling data only. We further define a pool as the body of oil and/or gas occurring in a separate reservoir and under a single pressure system.

Carbon dioxide in enhanced oil recovery

Oil reservoirs are deep underground, with the oil and gas contained in porous rock at high temperatures and pressures. Around 5 – 20%, of the oil can be produced from the field under its own pressure (primary production), but in most fields water is injected to displace the oil. This still leaves at least 50% of the oil behind in the reservoir. Further recovery can be obtained by injecting carbon dioxide that both displaces and dissolves the remaining oil. At least 71 projects worldwide use CO 2 flooding and produce a total of over 170 000 barrels of oil a day, worth around $1.3 billion a year. The cost of producing an extra barrel of oil ranges from $5 to $8 and thus is profitable at the present price of nearly $20 a barrel. In the majority of these cases, the carbon dioxide comes from natural underground sources and is piped to the oil field. The potential use of CO 2 flooding would be considerably greater, if large quantities of the gas, extracted from power stations, were available at low cost. For every kilogramme of CO 2 injected, approximately one to one quarter of a kilogramme of extra oil will be recovered. For most projects about as much carbon dioxide is disposed of in the reservoir as is generated when the oil is burnt. When CO 2 is at a sufficiently high pressure to form mixtures with the crude oil that are miscible in laboratory tests, up to 40% of the oil remaining in the field after water flooding can be recovered. Approximately half the water flooded oil fields in the US could be exploited profitably by CO 2 injection. Carbon dioxide flooding of the larger North Sea fields is a particularly attractive prospect, because the crude oil is light (composed of low molecular weight hydrocarbons) and the geology of the reservoirs is less heterogeneous than the American fields. A profitable project would be possible if the gas could be provided and piped to the reservoir at a cost of around $3.50 per thousand cubic feet or less.

Carbon Dioxide Flooding As An Enhanced Oil Recovery Process

Synopsis In earlier work(1–5), the fundamental and the field applications of carbon dioxide flooding were described. The presentation(5) at the Western Regional Meeting of SPE in 1991 focussed on a comparison of CO2 flooding for light and heavy oils, with examples from the field showing that CO2 flooding has recovered significant amounts of incremental oil under miscible as well as immiscible conditions. Carbon dioxide flooding for the enhanced recovery of heavy oils is important for Canada since it provides an alternative to thermal recovery. In this article the author will attempt to illustrate the state-of-the-art on CO2 flooding in general and how CO2 flooding relates to the recovery of heavy oils in particular. Introduction There is a great deal of industry interest in CO2 flooding as evidenced by the large number of field applications which have been initiated in the past decade(6). Additional field tests are certain to be carried out when CO2 supplies of acceptable purity and volumes are found. All major petroleum research centres, institutes, universities and government research institutions have projects relating to CO2 flooding. With two exceptions, the process normally involves the injection of CO2 initially, followed by a period in which CO2 is alternated, as small slugs, with another fluid, and terminates, with the injection of the principal driving or chase fluid which would be either water or gas. The two exceptions are the carbon dioxide stimulation process which is carried out in producing wells and is a stimulation technique very similar to a ""huff-and-puff' scheme. The other exception occurs in reservoirs which have such low pressure that they must initially be pressurized prior to the injection of CO2. Normally, such pressurization is by injection of water. Carbon dioxide flooding may be carried out either as a miscible or as an immiscible oil recovery process and has been studied in the laboratory or practiced in the field in the following modes:carbon dioxide stimulation;continuous CO2 injection;simultaneous injection of CO2 and water;alternating slugs of CO2 and water;injection of CO2 with H2S;injection of CH4 and CO2;CO2 and N2 mixtures;the CO2, SO2, combination;CO2 and LPG mixtures; andLPG followed by CO2. The most common way that CO2 flooding is being applied in approximately 60 depleted light oil reservoirs in the United States has been to initially repressurize the reservoir to the minimum miscibility pressure by injecting water. In a few cases, repressurization was accomplished by injecting CO2 from the start. Of course, this can be costly. For a reservoir depth of, say. 2500 m, one can expect the minimum miscibility pressure to be about 16 MPa and the reservoir temperature to be 90 °C. At these conditions, 350 m3 of CO2 would approximately equal 1 m3 in reservoir volume. Depending on the size of the reservoir and the cumulative past production the CO2 requirements can prove to be prohibitive.

Potential Of Non-Thermal Methods For Heavy Oil Recovery

Abstract Recovery of moderately viscous oils (below 2000 mPaS) from reservoirs which are unsuitable for thermal treatment may be possible by non-thermal methods. This paper addresses this problem within the framework of field and laboratory experience. Many heavy oil reservoirs in Canada fit this category: they are too thin, deep, or oil saturation is low, or have other undesirable features for a thermal recovery method to be successful. The non-thermal recovery methods considered are: improved waterfloods, polymer flooding, surfactant, caustic and other chemical floods, immiscible carbon dioxide flooding, solvent flooding, etc. Ranges in oil recovery as based upon field experience and from laboratory experiments are indicated. It is shown that non-thermal methods may be successful for heavy oil recovery under rather restrictive conditions. Based upon the data from some 113 field tests, it seems that immiscible carbon dioxide floods are more likely to be successful. In nearly all cases, the oil recovery is much lower than that attainable by thermal methods. This paper concludes with an evaluation of non-thermal recovery methods. Introduction Heavy oil deposits in Canada, Venezuela and the United States comprise several trillion barrels. Thermal methods, viz. steam injection and in situ combustion are best for recovering some of this oil, provided that the reservoir conditions are favourable. However, over half of the oil occurs in reservoirs that are not suitable for thermal methods. This is the case when the formations are thin (&amp;lt; 10 m), depths are large (&amp;gt; 1000m), formation permeability is too low to permit high enough injection rates, or the oil saturation is low, perhaps combined with a low porosity. Under such conditions, a non-thermal recovery method may be employed, which may be further modified for a viscous oil. Such methods would be expected to be applicable to moderately viscous oils (viscosity less than a thousand mPas), if the remaining conditions are favourable. This paper reviews alkaline flooding, polymer flooding, immiscible carbon dioxide flooding in detail, and discusses other non-thermal methods briefly. Results of laboratory investigations are discussed alongside field tests. Comprehensive tables list the laboratory data for all processes, as well as field data for each process tested. It is believed that the data presented would help in assessing non-thermal recovery methods for a specific reservoir. Furthermore, the laboratory data summarized provide an idea of the range of variability of results, and a comparison with the field recovery values underscores the problems associated with unscaled experiments. Problems in Viscous Oil Recovery The principal difficulty in the recovery of heavy oils is the high oil viscosity, leading to low oil mobility, which makes displacement by a cheap fluid, such as water or gas, inefficient on account of the "unfavourable" mobility ratio (i.e. mobility of the displacing fluid is greater than the mobility of the displaced oil). Under suitable reservoir conditions this may be corrected by the use of heat. However, this may be impractical for a variety of reasons, some of which were mentioned above.

Use of optimal control theory to optimize carbon dioxide miscible-flooding enhanced oil recovery

Optimal control theory is used to determine optimal injection strategies that maximize the profitability of the carbon dioxide enhanced oil recovery process. Based upon a modified black oil model, a comparative study was made to determine how optimization can improve upon currently practiced injection policies of a single carbon dioxide slug, simultaneous injection of CO 2 and water, and WAG injection. The results show that optimal slug volumes of carbon dioxide can be computed. Also, the wellbore pressure is shown to be an important control variable affecting the optimal performance of a carbon dioxide flood.