Conventional Oil Reserves Research Articles

High Temperature Simulated Distillation of Athabasca Vacuum Residue Fractions. Bimodal Distributions and Evidence for Secondary “On-Column” Cracking of Heavy Hydrocarbons

Decreasing conventional oil reserves and existence of large heavy oil and bitumen reservoirs demand novel and cost-effective production and upgrading schemes. One three sequential steps “visbreaking−adsorption−catalytic steam gasification” upgrading process was recently introduced by the group. Thermal cracked heavy molecules were shown to be key components for improved adsorption over solid sorbents. Characterization of the feedstock and the visbroken products is an important part of the study. In this paper, high temperature simulated distillation (HTSD) characterization is covered. Bimodal and monomodal HTSD chromatographic distributions were observed depending on sample relative abundance of heavy resins and asphaltenes. These polar compounds are responsible for the high temperature chromatographic mode. Secondary “on-column” cracking of heavy petroleum components was observed, however not contributing dramatically to the relative abundance of the chromatographic modes. Changes brought by thermal crac...

Reserves Estimation: The Challenge for the Industry

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Reserves estimation is one of the most essential tasks in the petroleum industry. It is the process by which the economically recoverable hydrocarbons in a field, area, or region are evaluated quantitatively. Downward revisions of U.S. Security and Exchange Commission (SEC)-booked reserves by some oil companies in 2004 brought the topic under public scrutiny. Confidence in reserves disclosures became a public issue, and there were calls from investors and lending institutions for more-reliable reserves estimates. Oil companies have responded by revisiting reserves-estimation procedures, and SPE, American Association of Petroleum Geologists (AAPG), World Petroleum Council (WPC), and Society of Petroleum Evaluation Engineers (SPEE) have launched a joint project to train reserves evaluators. A major goal in this initiative is preparation of training modules that represent industry's "recommended practices." Long before the issue caught the public's attention, however, reserves estimation was a challenge for the industry. The challenge stems from many factors, tangible and intangible, that enter the estimation process, and judgment is an integral part of the process. Uncertainty, along with risk, is an endemic problem that must be addressed. Consequently, the industry's record of properly predicting reserves has been mixed. Despite appeals from some quarters, there currently is no standardized reserves-estimation procedure. The purpose of this paper is to discuss various issues related to reserves, review reserves-estimation procedures, and make suggestions for improvements. Emphasis will be placed on reserves evaluation at the preproduction stage in which estimation errors generally have the highest economic effect. The discussed procedures pertain to conventional oil and gas reserves. Specific rules relating to booking reserves for regulatory purposes are outside the scope of this paper. Reserves Definition and Classification Fig. 1 shows how reserves are part of the petroleum resource base. Under the SPE/WPC definitions, "Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward" (Petroleum Reserves Definitions 1997). Commerciality implies commitment or expected commitment to develop reserves within a reasonable time frame. Depending on the degree of uncertainty, three main classes of reserves are recognized: proved, probable, and possible, the last-named two collectively called unproved. Proved reserves are those quantities that have reasonable certainty of being recovered, indicating a high degree of confidence. Proved reserves may be developed or undeveloped. Probable reserves are more likely than not to be recoverable, while possible reserves are less likely to be recoverable than probable reserves. Geological and engineering data form the basis of determination. Proved reserves assume recoverability under current economic conditions, operating methods, and government regulations. For unproved reserves, recoverability may be tied to future economic conditions and technology.

Of Note: Chavez's Populism Threatens the Economic Engine of His Revolution

Chavez's Populism Threatens the Economic Engine of His Revolution Ben Deering  Oil-rich states are getting richer. With higher commodity prices worldwide, extractive industries are proving very profitable. Indeed, governments are noticing the upsurge in profit, and are actively seeking more control over national resources. In Venezuela, such policies have already taken a large toll on current, and possibly future, energy production. To finance his extensive social spending increases and aid grants to political allies, Venezuelan President Hugo Chavez has increased the government's control of and taxes on the country's energy sector. Among President Chavez's largest targets has been the state-owned oil company Petróleos de Venezuela (PDVSA). Beyond simply relying on higher oil prices and taxes to generate income, in 2005 Mr. Chavez required PDVSA to spend roughly $4.4 billion of its $19.5 billion budget on social programs. This left only around $3 billion for critical investment projects after meeting the company's expenses—an astonishingly low figure given that PDVSA's wells have a natural decline rate of 25 percent per year, requiring an estimated $2.5 billion of investment annually to maintain current production levels.1 In 2006, the amount PDVSA set aside for social expenses rose to above $6 billion. Additionally, PDVSA revenues are siphoned off to fund the Fondo Nacional del Desarollo (Fonden), the government's national development fund. According to the finance ministry, as of July 7th the Fonden had received $4.6 billion from PDVSA since its inception in late 2005.2 Unfortunately, it is not just energy revenues that Venezuela uses inefficiently. The state's consumer-oriented energy subsidies keep prices low, and encourage Venezuelans to consume the highest level of electricity per capita in South America.3 Venezuela is also among the world's leaders in the amount of energy required to produce a unit of GDP. To this list, Venezuela can add inefficient human capital management. Shortly after his election, Chavez declared his desire to overhaul what he has called a "state within a state." His initial attempts to reform the state oil company met considerable resistance from large segments of the company's own management who had in prior years operated increasingly independently. Their independence ran directly counter to Mr. Chávez's vision for the company's role in a Venezuelan socialist renaissance. When many of [End Page 159] the company managers participated in the December 2002–February 2003 general strike, Chavez responded by firing over 20,000 of the company's 45,000 employees. 4 Although Venezuela has large oil reserves, President Chavez's policies are crippling production. Underinvestment in capital needs, awarding of oil service contracts based on companies' ideological orientation, and politically motivated layoffs of experienced personnel have combined to diminish current production and the future potential of Venezuela's complex oil reservoirs. The country's 79.7 billion barrels of proven conventional oil reserves, 151 trillion cubic feet of natural gas, and roughly 270 billion barrels of reserves of extra-heavy oil in the Orinoco Belt, mean that it remains the most important oil and gas producer in the hemisphere. Yet its output has fallen substantially.5 In February 1999 when Mr. Chavez took office, PDVSA was producing 3.3 million bbl/d and only 200,000 bbl/d was being produced by private oil companies. Currently, Venezuela's production capacity stands at 2.6 million bbl/d, but for the above stated reasons, PDVSA's overall capacity has dropped 1.8 million bbl/d. Venezuela is failing to meet its potential. Although Venezuela houses roughly three-times the number of oil reserves compared to the United States, America produces four-times as many barrels of oil per day. Overall, Venezuela's oil sector is now starved of technology, capital, and experience. Consequently, Venezuela has seen a pronounced slowdown in oil revenue growth from 62 percent in 2005 to just 21 percent for the first six months of 2006, despite strong world...

The Energy Innovation Network: Fueling an Integrated Energy Future

Abstract The convergence of increasing concern about energy supply and increasing public commitment to environmental protection provides an opportunity to mobilize public and private investment in energy innovation. To tap the vast Canadian resource potential, innovative new technologies are required-to unlock the large remaining conventional oil and gas reserves, take advantage of the hundreds of years of remaining production of bitumen, coal, and coal bed methane, and ensure increasing supply from renewable energy options. As Alberta's energy innovation strategy was developed, recognition grew that solutions to the pressing challenges described above emerge when we understand the energy industry as one interconnected system, integrated horizontally along the various energy sources and vertically along the value chain. This led to the creation of the Energy Innovation Network (EnergyINet) as the vehicle to facilitate strategic collaboration and innovation among industry, governments (federal and provincial), and the research community to address the challenges of ensuring an abundant supply of environmentally responsible energy. This paper describes, as an example, the approach taken in the development of oil sands technologies where a government-industry partnership was developed to share resources, build expertise, and lower technology risks. This provided the key tools that have lead to the oil sands becoming a significant resource relative to global energy demand. The paper argues that no one single source of energy will be sufficient to meet world or Canadian demand and consequently for the need for a collaborative initiative to facilitate a long-term (20- to 25-year) effort to implement an integrated energy innovation strategy. This integrated approach is built on the premise that strategic investment in a balanced portfolio of energy innovation "with a focus on common technology platforms and points of leverage across the portfolio" has the greatest potential for returns in economic, environmental, and social terms. Introduction The International Energy Agency (IEA) projects that global primary energy demand will increase by 1.7% per annum from 2000 to 2030, reaching an annual level of 15.3 billion tonnes of oil equivalent. The increase will be equal to two thirds of current demand(1). The world will remain heavily reliant on traditional forms of energy. Though renewables are expected to grow from a low base, they cannot displace fossil fuels as the overriding source of energy in this time scale. Fossil fuels are expected to supply over 90% of global incremental energy demand through 2030. Gas consumption is estimated to double between 2000 and 2030 in view of its cost competitiveness, ample availability, and environmental advantages. Oil will remain the largest fuel source with demand increasing by 1.6% per annum. Canada is the 5th largest energy producer in the world and is a net exporter of energy; these exports account for about 7% of the GDP. Canada is also a world leader in hydroelectric power development (24% of domestic consumption), but there is limited potential for development of new hydroelectric sites. Nuclear energy (5% of domestic consumption) is declining, and there have been no investments in new nuclear facilities for nearly 20 years.

Biological upgrading of heavy crude oil

Heavy crudes (bitumen) are extremely viscous and contain high concentrations of asphaltene, resins, nitrogen and sulfur containing heteroaromatics and several metals, particularly nickel and vanadium. These properties of heavy crude oil present serious operational problems in heavy oil production and downstream processing. There are vast deposits of heavy crude oils in many parts of the world. In fact, these reserves are estimated at more than seven times the known remaining reserves of conventional crude oils. It has been proven that reserves of conventional crude oil are being depleted, thus there is a growing interest in the utilization of these vast resources of unconventional oils to produce refined fuels and petrochemicals by upgrading. Presently, the methods used for reducing viscosity and upgradation is cost intensive, less selective and environmentally reactive. Biological processing of heavy crudes may provide an ecofriendly alternative or complementary process with less severe process conditions and higher selectivity to specific reactions to upgrade heavy crude oil. This review describes the prospects and strengths of biological processes for upgrading of heavy crude oil.

In Situ Viscosity of Oil Sands Using Low Field NMR

Abstract In heavy oil and bitumen reservoirs, oil viscosity is a vital piece of information that will have great bearing on the chosen EOR scheme and the recovery expected. Prediction of in situ viscosity with a logging tool would be very beneficial in reservoir characterization and exploitation design. Low field NMR is a technology that has shown great potential as a tool for characterizing hydrocarbon properties in heavy oil and bitumen reservoirs. An oil viscosity correlation has previously been developed that is capable of providing order of magnitude viscosity estimates for a wide range of oils taken from various fields in Alberta. This paper presents tuning procedures to improve the NMR predictions for different viscosity ranges, and extends the NMR viscosity model to in situ heavy oil in unconsolidated sands. The results of this work show that the NMR oil peak can be de-convoluted from the in situ signals of the oil and water, and the bulk viscosity correlation that was developed for bulk oils can be applied to predict the in situ oil viscosity. These results can be translated to an NMR logging tool algorithm, allowing for in situ measurements of oil viscosity at the proper reservoir conditions. Introduction Canada contains vast reserves of heavy oil and bitumen. With approximately 2.7 trillion barrels of oil in place, the Canadian deposits of heavy oil and bitumen are comparable in volume to the total of all the known deposits of conventional crude oil worldwide(1). As conventional oil reserves begin to decline in Canada, while worldwide demand for oil continues to increase, the industry focus is now shifting rapidly to the recovery of these heavy oil and bitumen reserves. Due to advances in technology, operating costs for heavy oil recovery are decreasing, and these reserves are now becoming economic to produce. The most important physical property of heavy oil that governs the recovery process is its viscosity. This parameter dictates both the economics and the technical possibility of success for any chosen recovery scheme. As a result, oil viscosity is often correlated directly to estimates of recoverable reserves(2). Unfortunately, laboratory measurements become less accurate and more difficult to obtain as viscosity increases. The oil that is removed from the core may also have been physically altered during the transport and handling of the sample, so the oil viscosity measured in the lab may not be representative of the actual oil properties in situ(2). In light of the shortcomings of conventional viscosity measurements, low field nuclear magnetic resonance (NMR) is considered as an alternative for estimating heavy oil and bitumen viscosity. The idea of using low field NMR as a tool for predicting oil viscosity is not a new one. Several models have been proposed in the literature(3–6), which can predict oil viscosities for conventional and heavy oil. An NMR oil viscosity model was also previously presented(7, 8) that is capable of making order of magnitude oil viscosity predictions for samples with measured viscosities ranging from under 1 mPa.s (cP) to over 3,000,000 mPa.s.

An evaluation of the U.S. Geological Survey World Petroleum Assessment 2000

This study compares the additions to conventional crude oil and natural gas reserves as reported from January 1996 to December 2003 with the estimated undiscovered and reserve-growth volumes assessed in the U.S. Geological Survey World Petroleum Assessment 2000, which used data current through 1995. Approximately 28% of the estimated additions to oil reserves by reserve growth and approximately 11% of the estimated undiscovered oil volumes were realized in the 8 yr since the assessment (27% of the time frame for the assessment). Slightly more than half of the estimated additions to gas reserves by reserve growth and approximately 10% of the estimated undiscovered gas volumes were realized. Between 1995 and 2003, growth of oil reserves in previously discovered fields exceeded new-field discoveries as a source of global additions to reserves of conventional oil by a ratio of 3:1. The greatest amount of reserve growth for crude oil occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in sub-Saharan Africa. The greatest amount of reserve growth for natural gas occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in the Asia Pacific region. On an energy-equivalent basis, volumes of new gas-field discoveries exceeded new oil-field discoveries.

Evaluation of the Miscibility and Contribution of Flue Gas to Oil Recovery Under High Pressure Air Injection

Abstract The improvement in the recovery of light oil by high pressure air injection (HPAI) involves a combination of complex processes, each contributing to the overall recovery. One of these processes is the spontaneous ignition of the air-oil mixture with complete oxygen utilization. This process generates flue gases, which are in contact with the reservoir oil at the displacement front. An experimental study was carried out to investigate the mechanism and contribution of miscible displacement, by in situ generated flue gases, to the recovery of light oil in reservoirs undergoing HPAI. The flue gas displacements were carried out on recombined reservoir oil in a slim tube apparatus at a reservoir temperature of 116 º C and pressures ranging from 27.77 MPa (4,028 psi) to 46.06 MPa (6,680 psi). Results show that miscibility could not be achieved between the test oil and flue gases under the test conditions. Experiments conducted between 41.28 MPa (5,987 psi) and 45.04 MPa (6,532 psi), however, gave an indication of near-miscible displacement of the test oil. The flue gases displaced the oil in a forward contacting extraction process, resembling a combined vapourizing/condensing multi-contact gas drive mechanism. The relatively high recovery, high extraction of oil components, and the pattern of flow behind the displacement front, exhibited at high pressures, demonstrate that near-miscible displacement by in situ generated flue gases could significantly contribute to oil recovery in light oil reservoirs undergoing HPAI. Introduction Air injection into high pressure reservoirs is an emerging technology for the enhanced recovery of light oils. It is probably the best hope for improved recovery from the world's ever declining reserves of conventional oil and, in particular, the profitable enhanced recovery of the enormous quantities of residual oil trapped in depleted and mature waterflooded light oil reservoirs(1, 2). Air is the most inexpensive, available gas that can be used to accelerate oil recovery. Air injection is especially applicable in low porosity and low permeability reservoirs where water injectivity is extremely low(3). Apart from providing a better interfacial tension (IFT) response(4), air injectivity is about ten times that of water in terms of reservoir volume(5), making air injection more advantageous than water injection in deep, tight, high pressure reservoirs. A number of successful high pressure air injection projects in light oil reservoirs have been documented in the literature(5–11). Most of these projects have been operating for many years, attesting to their technical and economic success. The improvement in recovery of light oil by HPAI involves a combination of complex processes, each contributing to the overall recovery. These processes include: reservoir pressurization, oil swelling, immiscible gas displacement, and superextraction when operating above the critical point of water. In addition to this, spontaneous oil ignition with complete oxygen utilization(2, 12, 13) and near-miscibility/miscibility of the in situ generated flue gases with the reservoir oil(13) are possible and advantageous processes. Apart from reservoir pressurization, oil swelling, and immiscible gas displacement, the mechanism by which the other processes occur in the reservoir and their contribution to oil recovery have not been discussed in clear terms in the technical literature(14).

Progress in the In Situ Recovery of Heavy Oils and Bitumen

Abstract Most of Canada's trillion barrels of petroleum consists of bitumen, and to a lesser extent, heavy oil. This total may be compared with the total Canadian production of light-medium crude oil to date, which is only 12 billion barrels. Mining is effective for the production of bitumen, but is limited to the minor fraction of the resource that is shallow; also mining involves significant environmental difficulties. The challenges of efficient in situ production are like those for other petroleum production activities:to find and define suitable reservoirs,to create conditions for oil to flow at economic rates, andto drain the reservoir systematically to obtain high recoveries. This paper discusses the following in terms of production rate, recovery, energy requirements and economic factors. Each topic is a step, sometimes a sideways step, in the search for a means to achieve high rates and recovery within the bounds of economic constraints.Cold production using vertical wells and horizontal wells.Stimulation by wellbore heating.Cyclic steaming using conventional wells.Steam Assisted Gravity Drainage (SAGD).Steam and Gas Push (SAGP).Cyclic Steaming with horizontal wells.Vapour Extraction (Vapex). Processes resulting in the displacement of oil by gas to a lower horizontal well show the most promise. The viscosity in the region around the horizontal well should be reduced to allow economic rates without gas coning. In SAGD, injected steam heats the oil and fills the reservoir as it drains, and rates of 79 – 159 m3/d (500 – 1,000 B/d) can be achieved with bitumen recoveries greater than 50%. Heat savings can be achieved by building a substantial gas concentration within the depleted region (SAGP). In Vapex, viscosity reduction is obtained by dilution with a olatile solvent; this is a promising approach for lower viscosity heavy oils. Another promising approach is cyclic steaming with horizontal wells, combined with gas addition to the steam to maintain drive. Introduction As conventional oil reserves become depleted, interest continues to grow in the improved recovery and utilization of Canadian tar sands and heavy oil. The resources are enormous in magnitude, and there have been great strides in technology. One approach, the mining and upgrading of shallow Athabasca deposits has, with the success of the Suncor and Syncrude projects, already become a major source of Canadian oil. Major expansions to both of these projects, as well as other new tar sand mining projects are underway. While mining overcomes the problem of moving the oil to the surface and of obtaining high recoveries, it requires the handling and disposal of vast amounts of solids and sludge, and it is only economic for the shallowest of deposits. The major part of the Canadian oil sand resource is too deeply buried for mining to be practical. This paper is concerned with the recovery of bitumen and heavy oils by in situ methods, i.e., by means of wells drilled from the surface.

Gas Injection EOR- A New Meaning in the New Millennium

Abstract Although the idea of injecting gases to improve oil recovery has been known for over three-quarters of the past century, it appears to be taking on a new meaning as we step into the new millennium. The oil price scenario remains consistently loyal to its rollercoaster past; the long awaited jump in the natural gas price has become a reality; the oil industry has made new strides in horizontal drilling with significant cost reductions; and the world's attention is focused on the industrialized nations to lead the way to control global warming by reducing greenhouse gas emissions. These evolving global issues combined with the ever-declining reserves of conventional crude oils appear to bring a new optimism to enhanced oil recovery (EOR) by gas injection. Added to this optimism are the well-accepted facts that waterflood recoveries from conventional oil reservoirs rarely exceed 40﹪ of the original oil in place (OOIP); that most waterfloods are maturing or close to their economic limits; and that chemically enhanced waterfloods appear to have become practically extinct in spite of their conceptual soundness. Therefore, gas-based EOR processes using horizontal wells appear to be the solitary hope for continuing profitable production from the large remaining reserves of conventional oil in Canada, the United States and the rest of the world. In what follows, we will briefly discuss-but not review-the conceptual basis for gas injection EOR processes and what we have conveniently overlooked in it, the historical developments, process design considerations, problem areas, and the future direction and potential of this time-tested technology. The Background The concept of injecting gases into reservoirs to improve oil recovery is an old one, dating back to the 1920s when the early research papers appeared. However, much of the progress in our knowledge of the physics and chemistry of multiphase flow through porous media seems to have occurred after the early 1950s. This progress encompassed the development of three main processes of enhanced oil recovery (EOR): thermal, chemical, and miscible. While the thermal EOR process and its variations were aimed mainly at recovering heavy oils by lowering their viscosity to enable their flow, the chemical and miscible gas processes targeted the light and medium gravity crude oils by lowering the interfacial tension between the injected fluid and the crude oil to minimize the trapping of oil in the rock pores by capillary or surface forces. Before discussing the background of gas injection EOR processes, we need to distinguish the term EOR from the more recent term of improved oil recovery (IOR). The EOR processes involve the injection of fluids to supplement the natural energy in the reservoir to displace oil to the producing wells. More importantly, the injected fluids interact with the reservoir rock-fluids system to create conditions favourable for enhancing oil recovery. These favourable interactions include oil swelling, interfacial tension reduction, oil viscosity reduction, rock wettability modification, and phase behaviour effects(1). Thus, simple waterflooding and dry gas injection for pressure maintenance are not EOR processes, as they do not involve any of these interactions.

Vapex: An Efficient Process for the Recovery of Heavy Oil and Bitumen

Summary The Vapex (vapor extraction) process may be a viable technique for the recovery of highly viscous heavy oil and bitumen. The size of the estimated heavy oil and tar sand resources in the United States amounts to 100 billion bbl and 62 billion bbl of oil in place (OIP), respectively. Although this represents a small fraction of the total world reserves, it is about one-third of the total estimated crude oil discovered in the United States. The world estimate of this resource is about 6 trillion bbl, six times the conventional oil reserves, and may be the future source of energy. Efficient extraction of these highly viscous crude oils poses a serious challenge to petroleum engineers. In some of the heavy oil reservoirs steam flooding and in-situ combustion processes were partially successful. For thick tar sand reservoirs, the steam-assisted gravity drainage (SAGD) process proved to be effective. However, thermal processes, in addition to other disadvantages, suffer from energy inefficiency caused by heat losses. The Vapex process involves injection of vaporized hydrocarbon solvents into heavy oil and bitumen reservoirs; the solvent-diluted oi1 drains by gravity to a horizontal production well. Recent research has shown that the process is highly energy efficient, environmentally friendly, causes in-situ upgrading, and requires low capital investment compared to its competitive process, SAGD. The applicability of the Vapex process may even surpass SAGD in thin reservoirs, reservoirs underlain by aquifer, offshore operations, etc. Some experimental results, a theoretical analysis, and the feasibility of this process for implementation in heavy oil and bitumen reservoirs will be presented.

The Promise And Problems of Enhanced Oil Recovery Methods

Abstract Enhanced oil recovery (EOR) methods are outlined in a systematic and balanced manner, and the current impact of these methods is assessed in light of field experience. The main EOR methods are described briefly, their current status is described, and the reasons for the lack of success are examined. The paper does not rely on voluminous statistics, nor does it give another set of screening criteria. Rather it develops the process discussion in terms of mobility ratio and capillary number. Successful EOR methods such as SAGD are modifications of standard methods to unusual reservoir conditions. Certain EOR methods, such as chemical floods, have inherent limitations, explaining the lack of success in the field in contrast to laboratory. Introduction Primary oil recovery can vary from zero to over 50% of the original oil in place (OOIP), depending on the type of hydrocarbon and the reservoir drive. Primary recovery from oil sands is zero, whereas that for a water drive in a light oil reservoir can reach 50%, or even more in the case of an efficient gravity drive. Secondary recovery is usually taken to mean waterflooding, and can again vary from zero (oil sands) to a few per cent (heavy oils) to 20 - 50% of the initial oil in place (IOIP) for a light oil. Enhanced oil recovery usually implies recovery beyond the secondary stage. In the case of very viscous oils and oil sands, with little or no primary and/or secondary productivity, EOR may refer to the recovery techniques employed from the start. We are thus concerned with a whole range of unconventional-usually costly oil recovery methods, only a few of which have been shown to be commercially successful, under favourable conditions. Improved oil recovery (IOR) sometimes signifies measures taken during-not after-the primary and secondary stages to increase oil recovery. This is often the case in offshore oil reservoirs where the economics would not permit operation beyond the secondary stage. As the conventional oil reserves in U.S.A. and Canada decline, EOR is gaining increasing importance. The extensive survey published every two years by the Oil & Gas Journal (Moritis(l)) shows that the EOR production in Canada and U.S.A. is about 25% and 10%, respectively, of the total oil production, and is increasing. Table 1, based on the survey, gives the oil production rates for various EOR method, for 1994. Miscible displacement is the dominant recovery method in Canada, with steam injection gaining fast. The latter is the principal recovery method in U.S.A., with miscible carbon dioxide flooding a distant second. In Canada, steam injection will continue to increase in importance, as the heavy oil/bitumen resources are exploited. In U.S.A., steam is limited to California heavy oil reservoirs, and carbon dioxide flooding to areas with inexpensive sources. Chemical flooding methods have declined with the drop in oil prices over the last decade. These methods have the promise of recovering oil from depleted light oil reservoirs. Hundreds of EOR projects are being operated. Many are experimental.

Effect of Asphaltene Deposition On the Vapex Process: A Preliminary Investigation Using a Hele-Shaw Cell

Abstract Recovery using vaporized hydrocarbon solvents near their dew points, termed "Vapex" (vapour extraction), is emerging as a possible alternative to the inefficient thermal processes currently in use for the recovery of the huge reserves of heavy oil and bitumen. In this new process, solvent dilutes the highly viscous heavy oil and bitumen and aids the flow by reducing viscosity. Propane and ethane are considered to be the mast suitable solvents for the process. However, a mixture of butane, propane and ethane can also be used, depending on" the prevailing pressure in the reservoir. Oil is produced by gravity drainage to horizontal wells. One important advantage of this approach can be the in-situ upgrading of heavy oil by deasphalting; this can make the produced crude comparable to lighter oils in quality. Moreover, elimination of the undesirable asphaltenes from the crude can solve several downstream problems. When sufficient solvent is employed to produce deasphalting, one important question is - "Do the deposited asphalteoes plug the reservoir and affect the flow of diluted oil? " An investigation, carried out in a Hele-Shaw cell using propane and several heavy crudes that concluded that asphaltene deposition does not prevent the flow of oil through the reservoir for the proposed production scheme, is described in the present paper. It has been observed that deasphalting takes place if the injected propane pressure is close to or higher than the vapor pressure of propane at the same temperature. The mechanism of the associated process is studied and described. In another set of experiments, in the Hele-Shaw cell, the drainage profiles of heavy oil and bitumen (solvent bitumen interface) in the presence of propane were studied. These were used to estimate the hypothetical "Vapex parameter" that combines the effect of viscosity, diffusivity, density arid solvent concentration along with reservoir parameters, formulated from the model developed by Butler and Mokrys(18). This parameter was used to scale the results for prediction of field flow rates. A comparison of this parameter for crudes of different reserves gives the relative rates of production from these reservoirs. Introduction With the decline of conventional oil reserves, a major thrust of oil industries throughout the world is on the exploitation of heavy oil and bitumen reserves. The amount of this crude oil reserve is twice as much as that of the conventional oil reserves(1). The estimated OOIP of heavy oil in Canada is 400 billion m3 (2), which is twice that of the total conventional oil reserves of all Gulf countries. Alberta in particular is very rich in heavy oil and tar sand deposits, the total estimated reserve being 1.6 trillion barrels buried at a depth of 0-800 m, although only 5% of this reserve is recoverable by open pit mining from shallow reservoirs(3). FIGURE 1: Effect of solvent concentration and temperature on bitumen viscosity. (Available in full paper) In most cases, conventional recovery techniques cannot be implemented in the heavy oil and bitumen reservoirs due to the very high viscosity of the oil.

Horizontal Producer Wells In In Situ Combustion (ISC) Processes

Abstract A simple 3-D physical model has been developed to investigate the use of horizontal producer wells in in situ combustion processes. The semi-scaled 3-D model was a rectangular box with 40 cm by 40 cm by 10 cm dimensions. Dry in situ combustion experiments were conducted with three different well configurations (1) a vertical injector and horizontal producer; (2) a vertical injector and two horizontal producers; and (3) injector and producer, both vertical. A matrix of 60 thermocouples was used to obtain temperature profile information, ill the vertical and horizontal mid-planes. Most experiments were conducted with sandpacks containing a high saturation of heavy crude oil SOi ≈ 0.80. For each horizontal well configuration, the effect of oxygen flux and oxygen enrichment (21% and 35% oxygen) was investigated. Combustion peak temperatures up to 400 ºC were recorded, with oil recoveries exceeding 66% OOIP for the single horizontal producer well case. The recovery using two horizontal producer wells was 71.5% OOIP, higher than both the vertical producer and horizontal producer well cases. Generally, a much more stable propagation of the combustion front was observed for the single horizontal well vs single vertical well configuration. The vertical sweep especially was noticeably stabilized compared to the progressive tendency for gas override developing along the mid-plane of the vertical well experiment. Both single and double horizontal wells gave an earlier commencement of oil production and at a higher rate subsequently. However, the additional incremental oil recovery achieved by the double horizontal well was proportionately lower than indicated by theperformance of the single horizontal well, owing to interference between wells. At increased injected oxygen flux, the oil recovery reduced due to oxygen channelling through to the production end, causing higher rates of low-temperature oxidation ahead of the combustion from. Significant improvement of the combustion efficiency occurred with enriched air, but the oil recovery was lower due to higher fuel consumption. Overall, there was a very significant improvement in the quality of the produced oil using the horizontal well arrangement, Compared to that achieved with the single vertical well. Introduction The demand for crude oil and the increasing difficulty of discovering new large reservoirs, as well as the decrease in Conventional oil reserves, has generated special interest in heavy oil and tar sands. The high viscosities of heavy oils at reservoir conditions is the predominant factor limiting economic recovery. Any reduction in the oil viscosity will create an increase in oil mobility and therefore improve production. The most effective method of lowering the viscosity is by the application of heat to the reservoir. Heat may be introduced into the reservoir in the form of hot water, gases or steam lt may also be generated in situ by burning part of the oil in the reservoir, This process is known as in situ combustion or ISC. Fireflooding or ISC is a thermal EOR method in which heat is generated within the reservoir by igniting the formation oil and then propagating a combustion front through the oil bearing media.

The Rise of Interfering Solvent Chambers: Solvent Analog Model Of Steam-Assisted Gravity Drainage

Abstract In a previous paper the authors described, both experimentally and theoretically, the sideways spreading of a solvent region as bitumen is leached in situ and the heavier solution drains by gravity towards a production well below. In this paper, new experimental and theoretical studies towards leaching of bitumen by a lighter solvent are described. The mechanism differs markedly from that for the sideways motion of the leaching surface but is closely analogous to that observed for rising steam chambers in steam-assisted gravity drainage. An experimental technique was developed that utilizes a vertical Hele-Shaw cell. The experimental work led to the observation that a boundary layer, delimited by two shock fronts which are characterized by sudden changes in concentration, is formed around a rising solvent finger. The boundary layer mechanism is relevant to miscible fooding in general and it is believed that this is the first time the phenomenon has been observed and described theoretically. A solvent chamber theory was developed which predicts, without arbitrary parameters, the drainage rate, solvent concentration at both shock fronts, the shape of the solvent fingers and the width of the boundary layer. A comparison between experimental and predicted values shows a degree of agreement which is encouraging. Introduction The remaining conventional oil reserves in Canada are estimated at 0.8 billion m3 and the rate of new onshore discoveries is declining. As large oil discoveries have become rarer, conventional oil reservoirs are becoming increasingly marginal. Furthermore, there are large exploration costs and the development of offshore and Arctic fields requires huge investments. In contrast, the enormous bitumen deposits in Alberta are well known. Most of these untapped oil resources lie under 0 to 520 m of overburden and hold more petroleum than the conventional oil fields of the Persian Gulf. They are contained in sand and carbon sedimentary formations of the Athabasca, Cold Lake, Peace River and Wabasca regions as well as in the so called Carbon are Trianglel. The total oil-in-place for these deposits has been estimated to be more than 400 billion m3 (2.7 trillion barrels)(1). About 12 billion m3 of the tar sand deposits are at sufficient shallow depth (0 to 46 m) to be potentially mineable. The deeper deposits can only be produced by in situ methodsl. The major obstacle to the production of bitumen by in situ recovery methods is the high viscosity of the bitumen in its native state; this is, typically, 100000 mPa.s for Cold Lake and 1 000 000 mPa.s for Athabasca bitumen deposits. Such high values of in situ viscosities preclude primary or secondary recovery techniques and require the direct implementation of tertiary (or EOR) methods, in particular the thermal processes (cyclic steam injection, steam drive, hot water drive and in situ combustion) and the miscible gas processes (hydrocarbon miscible and carbon dioxide miscible flooding). More than 80% of EOR production is by thermal methods. Steam-based thermal recovery processes, particularly the cyclic steam technique, are the most widely used.

Aspects of Tar Sands Development in Nigeria

Abstract Development of Nigerian massive reserves of crude bitumen and associated heavy oil is imminent in view of the impacts that the huge importation of these materials and their products have on the nation's economy, coupled with the depleting reserves of Nigerian conventional oil. This article reviews the extent of the tar sands resources in Nigeria and highlights the appropriate production technology options and their environmental implications. The utilization potentials of these resources are also enumerated, as well as the government's role in achieving accelerated, long-term tar sands development in the country.

Requirements For Major Oil Sands Mining Projects In Canada

Abstract Canadian conventional oil production is declining and any significant new conventional oil discoveries are located in remote, high cost frontier areas. Synthetic crude oil and bitumen production from the vast, known oil sands in Alberta could offset the decline. Although oil sands tend to be an expensive source of supply, their abundance and proximity to markets and industrial centres, as well as the significant potential for reducing production costs through technology improvements, make them attractive candidates for commercial development. For this to become reality, certain prerequisites need to be in place. Since oil sand leases were first granted in northeast Alberta in the late 1950s, only two major oil sands mining projects have been developed. Although several similar oil sands projects have been proposed since then, none hove proceeded much beyond the design stage. This paper reviews the development history and nature of oil sands mining projects, examines the requirements for major oil sands mining projects in Canada and the lessons leaned from previously proposed projects. The paper focusses on the impact that stakeholder commitment, appropriate fiscal terms, corporate financial strength, technology development and readiness, quality project development and operational excellence market understanding, resource quality and the balancing of resource development with environmental responsibility have on the feasibility of developing this resource. Introduction Over the next 15 years, production from Canada's conventional established oil reserves are expected to decline by up to 50%. New conventional oil discoveries in remote high-cost frontier areas and synthetic crude oil (SCO) and bitumen production from vast known oil sands resources could help to offset this decline. Already Alberta's oil sands are playing a significant role in meeting current energy demands. The combined bitumen and SCO production from these in situ and surface mining projects account for about 20% of Canada's daily oil production. Although the potential of the Athabasca oil sands has been known for more than 200 years, development of the resource did not begin until the 1930s. The first commercial project started production in 1967. In 1990, the Athabasca deposit, home of the Suncor Inc. and Syncrude Canada Ltd. commercial mining projects, was the source of 33 130 m3/d (208 390 bbl/d) of SCO or 13% of Canada's oil production. Since production from these two operations first began, six similar oil sands mining projects have been proposed. However, none have proceeded much beyond the design stage. The seventh project, the OSLO Project is in its pre-appropriation stage. The OSLO Project promises an additional 12 700 m3/d (80 000 bbl/d) of SCO or 5% of Canada's daily oil production. Development History Background Development of the Athabasca oil sands as a source of crude oil reserves has been slow. Research into the nature of the oil sands started in the early 1880s when researchers at the Geological Survey of Canada in Ottawa conducted an experiment to separate the bitumen from the sand using hot water.

Technology Requirements For Mineable Oil Sands By The Year 2010

Abstract Alberta's reserves of conventional erode oil, natural gas, heavy oil and oil sands represent more than 90% of Canada's total energy reserves in these categories. Of these heavy oil and oil sands. constitute more than 60% of Alberta's total. Current forecast point out a decline in conventional reserves as production exceeds new discoveries. This trend is expected to continue with fewer and smaller prospects remaining to be discovered. The decline in conventional reserves, however, could be made up by an orderly development of oil sands and heavy oil projects. Based on the magnitude of the unconventional reserves, (approximately 300 billion tonnes bitumen in place), one could observe that the prospects for maintaining Canada's energy self-sufficiency are contingent on the production of heavy hydrocarbons from oil sands and heavy oil. The development of new surface mineable oil sands projects require large capital investment and their operations are labour intensive. Therefore, the total cost of synthetic crude production from new projects is not competitive with the most conventional production operations. However, oil sands have no exploration costs and present minimal exploration risks. In addition, the experience gained in oil sands operations during the last two decades has reduced actual production costs by one-half; but, the cost discrepancy between the conventional oil and synthetic crude oil, is significant enough to justify serious R&D efforts in oil sands. This paper points out the importance of oil sands for the future energy supply in Canada and identifies the R&D as the key to further commercial development of this valuable resource. The paper proposes a methodology and a set of criteria for determining technology requirements and ranking them. Finally, it provider a select list of areas for technology development and offers a series of practical recommendations. Introduction The rationale behind the Alberta Chamber of Resources interest in the long-term technology requirements is the recognition of the fact that the future economic competitiveness of bitumen or synthetic crude production from oil sands will be contingent upon further improvements in both capital and operating costs. Any significant cost reduction, in turn, can only be achieved through advancements and breakthroughs in technology. The Chamber recognizes the progress recorded in recent years and the current R&D efforts in diverse area of oil sands technologies. However, the Chamber is not aware of the existence of a long-term plan for oil sands R&D to guide the funding agencies and the technology developers in identifying the needs and determining the priorities. Therefore, the Chamber is concerned that in the absence of an over-all R&D road map, sufficient funds may not be available or the precious few funds that are available, may not be allocated to the appropriate R&D programs, The ACR Oil Sands Task Force's identification of the future technology requirements is based on a projected scenario which points out the importance of fossil fuels well beyond the year 2010. In this scenario, western Canada's oil sands and coal resources are predicted to supply a major portion of Canada's energy requirements throughout the 2lst century.

Investment Opportunities In Canada's Oil And Gas Industry

Abstract Canada and the Oil and Gas Industry Canada offers many attractive opportunities to investors seeking capital appreciation. Canada's oil and gas industry offers the following advantages: abundant natural resources; a strong economy; attractive geological potential; stable governments that encourage exploration and development; access to growing markets, particularly the United States; and, an equitable fiscal environment. Natural Resources Canada is the second largest country in the world, covering an area of 9.8 million km2 (3.8 million square miles). In addition to being highly industrialized, Canada has a large and varied base of natural resources. In terms of hydrocarbon production, Canada is the world's third largest producer of natural gas and the tenth largest producer of crude oil. Many of Canada's other natural resources are also impressive in world ranking:—third largest producer and exporter of metallic minerals;—largest pulp and paper producer;—largest producer of uranium;—second largest supplier of electrical power; and—second largest grain exporter. The Economy Canada has a population of 26 million and boasts the seventh largest economy in the industrialized world. The country's Gross Domestic Product (GDP) is in the order of $680 billion. With expansion of less than 1% in 1990, the real GDP completed its eighth consecutive year of growth since the 1982 recession. No real growth is forecast for 1991. Capital investment, as measured by business capital formation, has increased steadily since 1982 reaching nearly $80 billion in 1990. Canada has a work force of over 12 Million. Consumer prices in Canada have increased less than 5% annually over the past eight years and are expected to be stable in the near term. The value of oil and gas production for 1990 is estimated to be $22.1 billion. Capital expenditures in the oil and gas industry during 1990 are estimated at $6.3 billion. Exports of oil, natural gas, and petroleum products for 1989 were valued at $9.7 billion, offset by imports of $5.1 billion. Geological Potential Canada's oil and gas activity is centered primarily onshore in the large Western Sedimentary Basin, which extends from the province of British Columbia, at the nation's western extreme, eastward through Alberta, Saskatchewan and Manitoba. The province of Alberta is Canada's largest producing jurisdiction, accounting for 85% of the total hydrocarbon production. By the end of 1987, 2.70 × 109 m3 (17 billion barrels) of conventional oil and 3.67 × 1012 m3 [130 trillion cubic feet (tcf)] of marketable natural gas had been discovered in western Canada. In its latest report(1), the National Energy Board (NEB) of Canada estimates remaining conventional oil to be discovered in western Canada at 0.59 × 109 m3 (3.7 billion barrels). The NEB also estimates that 2.34 × 1012 m3 (83 tcf) of natural gas remains to be discovered in western Canada (Fig. 1). In addition to extensive reserves of conventional light crude oil and natural gas, Canada has a vast resource base of unconventional deposits such as heavy oil and oil sands in northern Alberta and Saskatchewan.

Geology and Hydrocarbon Potential of the Soviet Union

The Soviet Union is the world's largest producer of oil and natural gas. Soviet oil production averaged 12.1 million bbl per day in 1989 with gas production of 79 bcf per day. Estimates of Soviet proved reserves fall within the range of 50 to 80 billion bbl, which gives the Soviet Union the world's greatest concentration of proved conventional crude oil reserves outside the Persian Gulf. In addition, the Soviet Union contains estimated proved reserves of 1500 tcf of natural gas, constituting over 38% of the worldwide total. The basins of the Soviet Union can be generally separated into five categories based upon geography, geology, and exploration maturity. The southwestern flank of the Soviet Union, from the Carpathians to Central Asia, contains a series of late Mesozoic to Tertiary basins associated with the closing of the Tethys Ocean and the Tertiary Alpine Orogeny. Because these basins contain shallow production and are near population centers and in moderate climates, they were the first explored and provided virtually all Soviet production prior to the Second World War.