Showing papers on "Steam injection published in 2013"

Current Overview of Cyclic Steam Injection Process

Abstract: Cyclic Steam Injection (CSI) is an effective thermal recovery process, in which, several driving mechanisms define the success of the process; i.e. viscosity reduction, wettability alteration, gas expansion, etc. This process was first applied in late 1950s. Then, it has been applied world-wide successfully to both light and heavy oil reservoirs. To increase the effectiveness of CSI, process was varied by chemical addition to steam, application of horizontal wells and introduction of hydraulic fracturing. With these modern technologies, average 15% of recovery factor of conventional CSI producers back in 1980’s boosted up to approximately 40%. The method is attractive because it gives quick payout at relatively high success rate due to cumulative field development experiences. However, this is still uncompetitive in terms of ultimate recovery factor compared to that of other steam drive methods such as steam flooding (50-60% OOIP) or SAGD (60-70% OOIP). Recent studies related to the CSI have focused on either the optimization of chemical additives and fracture design or questioning on geomechanical solutions to poroelastic effects. In addition, most papers discuss about follow-up process posterior to CSI such as in-situ combustion, CO2 injection and steam flooding. This study is oriented to overview of the past and current status of CSI process in technical aspects with discussion of commercial cases throughout the world. A summarized review is given on the potential importance of encouragement of further investigation of Cyclic Steam Injection.

Influence of Steam Injection during Calcination on the Reactivity of CaO-Based Sorbent for Carbon Capture

Abstract: Calcium looping is an emerging CO2 capture technology based on cyclic calcination/carbonation reactions using calcium-based sorbents. Steam is typically present in flue/fuel gas streams from combustion or gasification and in the calciner used for sorbent regeneration. The effect of steam in the calciner on sorbent performance has received little attention in the literature. Here, experiments were conducted using a thermogravimetric analyzer (TGA) to determine the effect of steam injection during calcination on sorbent reactivity during carbonation. Two Canadian limestones, Cadomin and Havelock, were tested, and various levels of steam (up to 40%) were injected in the sorbent regeneration process for 15 calcination/carbonation cycles. All concentrations of steam examined were found to increase sorbent reactivity for carbonation for both sorbents. In these experiments, 15% steam concentration with calcination had the largest impact on carrying capacity for both sorbents. Steam changes the morphology of the ...

Open-source LCA tool for estimating greenhouse gas emissions from crude oil production using field characteristics.

Abstract: Existing transportation fuel cycle emissions models are either general and calculate nonspecific values of greenhouse gas (GHG) emissions from crude oil production, or are not available for public review and auditing. We have developed the Oil Production Greenhouse Gas Emissions Estimator (OPGEE) to provide open-source, transparent, rigorous GHG assessments for use in scientific assessment, regulatory processes, and analysis of GHG mitigation options by producers. OPGEE uses petroleum engineering fundamentals to model emissions from oil and gas production operations. We introduce OPGEE and explain the methods and assumptions used in its construction. We run OPGEE on a small set of fictional oil fields and explore model sensitivity to selected input parameters. Results show that upstream emissions from petroleum production operations can vary from 3 gCO2/MJ to over 30 gCO2/MJ using realistic ranges of input parameters. Significant drivers of emissions variation are steam injection rates, water handling req...

The Dynamic Interplay of Oil Mixing, Charge Timing, and Biodegradation in Forming the Alberta Oil Sands: Insights from Geologic Modeling and Biogeochemistry

Abstract: Regional-, field-, and reservoir-scale studies of the petroleum geology, petroleum biogeochemistry, and oil fluid properties of the western Canada oil sands produce the first high-resolution model of oil charge systematics for the oil sands. The sources and alteration history of the Lower Cretaceous and underlying Mesozoic and late Paleozoic oil fields of north-central Alberta (Peace River Arch [PRA] area) were investigated using a very large database of public and in-house data to define the unaltered end-member oils that charged the oil sand reservoirs and to delineate the reservoirs in the study area that are still biologically active today. Bulk chemistry and stable isotopic analysis of oils, in combination with the quantitative analysis of biodegradation-resistant saturated and aromatic hydrocarbon molecular indicators, revealed a complex of oil charge pathways to the oil sands on a field and reservoir scale. The molecular chemistry of the Peace River oil sand bitumen shows oil charge from the Jurassic Gordondale (oil Family Z) in the west along the Montney and Gething formations, mixing with vertical oil charge from the Exshaw Formation east of the Debolt anhydrite facies pinch-out. The Peace River oil sand fields that have received significant Gordondale-sourced oil charge are able to be cold produced, whereas the dominantly Exshaw-sourced oils are too highly degraded for cold production. Most likely, no Gordondale source contributed to the Exshaw source-dominated Athabasca, Cold Lake, and Lloydminster accumulations; however, further investigation of the possibility of some low-maturity Duvernay- and/or Ostracod-sourced oil contribution to the oil sands is still warranted. The precursor oils to the Peace River, Athabasca, Buffalo Head Hills, and Wabasca oil sands were the earliest expelled, lowest maturity petroleum from these source rocks with API gravities in the 20s and with high initial viscosities. The complex vertical and lateral heterogeneities of oil compositions and fluid properties seen in the PRA area reflect variations in oil charge maturity, migration pathways, and varying levels of biodegradation, conditioned by highly variable oil charging. The complexity of the petroleum systems and variation in source organic facies observed in this study are probably typical of the extremely large petroleum accumulations that dominate the world's petroleum occurrences.

A new reaction model for aquathermolysis of Athabasca bitumen

Abstract: Aquathermolysis of bitumen occurs when it is thermally cracked in the presence of water. Current in situ technologies for bitumen production, such as Cyclic Steam Stimulation and Steam-Assisted Gravity Drainage, inject high pressure, high temperature steam in the reservoir to heat the bitumen which in turn lowers its viscosity enabling flow to a production well. Thus, the major physical effect of steam is the heating of bitumen which mobilises it. Beyond physical interactions, chemical effects also result: steam heating produces acid gases, such as carbon oxides, sulphur dioxide and hydrogen sulphide along with small amounts of hydrogen and methane. For steam-based in situ bitumen recovery processes, nearly all analyses, including simple drainage theories and thermal reservoir simulations, focus solely on the physical processes: heat transfer, fluid flow and thermodynamic equilibrium. However, steam chambers are also underground reactors: bitumen aquathermolysis occurs due to high temperatures and water saturation. Here, we describe a new in situ aquathermolysis reaction scheme for Athabasca bitumen to predict hydrogen, methane, carbon oxides, hydrogen sulphide and other heavy molecular weight hydrocarbons. Reaction parameters were fitted against one experimental data set and validated against other independent experimental data sets, both from the literature. Our results indicate that, to more accurately predict gas compositions and rates, the effects of aquathermolysis should be taken into account in reservoir modelling. © 2012 Canadian Society for Chemical Engineering

Heavy oil production by carbon dioxide injection

Abstract: With the depletion of light oil, heavy oil is becoming one of the most promising resources for meeting future energy consumption. Heavy oil resources are abundant, but the traditional water flooding method can only achieve less than 20% of heavy oil recovery. Thermal recovery has proven effective in producing heavy oil, but not suitable for many heavy oil formations that are either thin or buried deep underground. Carbon Dioxide injection is a ‘win-win’ enhanced oil recovery (EOR) technique for many heavy oil fields. Injected CO2 not only increases heavy oil output, but also traps injected CO2 underground. Carbon dioxide effectively recovers heavy oil thanks to several mechanisms, including oil swelling, viscosity reduction, and blow-down recovery. This review discusses the advances of CO2 flooding at both laboratory scale and field scale. Laboratory tests show that CO2 can significantly improve heavy oil recovery. Several field cases in the USA, Turkey, Trinidad, and China are reviewed. Field experiences show that CO2 flooding is a successful EOR method for heavy oil fields. However, some issues were encountered in field applications, such as early gas breakthrough, corrosion, CO2 availability, and high costs.

Heavy Oil and Bitumen Petroleum Systems in Alberta and Beyond: The Future Is Nonconventional and the Future Is Now

Abstract: Global bitumen and heavy-oil resources are estimated to be 5.6 trillion bbl, with most of that occurring in the western hemisphere. In the past decade, significant advances in the development and production of these resources have occurred by way of the critical integration of geology, geophysics, engineering, modeling economics, and transportation. Bitumen and heavy-oil deposits are mainly unconsolidated sands bound together by biodegraded bitumen. In the case of the world's largest oil-sand and heavy-oil deposit, located in western Canada, the oil sands occur in deposits of low sedimentary accommodation on the distal side of a foreland basin. Hydrocarbons were derived from Mississippian Exshaw and/or Mesozoic source rocks. The hydrocarbons migrated eastward several hundred kilometers to accumulate and become biodegraded on the shallowly buried, low-temperature, northeastern margins of the basin. The hydrocarbons accumulated in tidally influenced fluvioestuarine sediments, midchannel bars, brackish bays, bay-head deltas, and tidal flats. Elsewhere, in another major global heavy-oil resource, the Oficina Formation in Venezuela was similarily deposited in fluvioestuarine to deltaic settings. Current in-situ oil-sand development focuses on steam-assisted gravity drainage (SAGD) technology and, to a lesser degree, cyclic steam stimulation (CSS). Other emerging technologies being piloted include in-situ combustion, electrothermal dynamic stripping, and passive heating-assisted recovery methods. Water supply and disposal is an ongoing critical component for the mines and in-situ development. In the surface mines, hydrotransport, typically using recycled and brackish water, has major requirements for water, whereas fresh to saline water is used to generate steam for the in-situ bitumen heating. The development of oil sands requires a delicate balance between resource extraction regulatory systems, environmental issues, and long-term sustainability. In areas of in-situ SAGD development where overburden is shallow, cap rock integrity is also critical to prevent steam escape from mixed hydrocarbon and steam chambers into ground and surface waters. For surface mines, experimental new bacterial-remedial biotechnology shows promise for reducing sedimentation time of fines and toxin removal from tailings ponds. Thus, to cost-effectively develop oil-sand resources of the world, it is critical that technological innovation continue to develop to minimize environmental impacts and to more efficiently develop these strategic resources.

Cold Lake Commercialization of the Liquid Addition to Steam for Enhancing Recovery (LASER) Process

Abstract: The Cold Lake project, in Alberta, Canada, is one of the world’s largest heavy oil in-situ thermal developments with oil production of about 24,000 m3/d (150 kB/d) from more than 4000 wells. The world class Cold Lake hydrocarbon resource is a bitumen deposit, featuring in-situ viscosities in excess of 100,000 cP. The high viscosity of Cold Lake bitumen severely limits steam injectivity below fracture pressure, necessitating the development throughout the 1970s and 1980s of a modified cyclic steam stimulation (CSS) recovery process. Imperial Oil and ExxonMobil are pursuing a research program to develop the next-generation of bitumen recovery processes that use hydrocarbon solvents as a mobilizing agent, reducing greenhouse gas (GHG) emissions relative to the current commercial recovery processes. Imperial and ExxonMobil are pursuing three processes: a solvent-only process known as Cyclic Solvent Process (CSP), a solvent assisted SAGD process and a solvent assisted CSS process known as Liquid Addition to Steam for Enhancing Recovery (LASER). LASER has the potential to increase oil recovery by more than 5% and reduce direct GHG emissions intensity by approximately 25%. This paper describes the first commercial application of LASER. The Cold Lake H trunk LASER project is to date the world’s largest implementation of a thermal solvent recovery process, with injection of 297 km3 (1.87 million barrels) of solvent into the 240 well project. This paper describes the successful operation of this thermal solvent project over a six year period; including reservoir numerical simulation work to develop bitumen and solvent production forecasts, development of field solvent production measurement methods, and the recovery process learnings from the first cycle of LASER operations. Completion of the first commercial LASER cycle has demonstrated on a large scale the success of solvent addition as a means to increase thermal efficiency and oil production in a heavy oil thermal recovery operation.

Application of Fast-SAGD in Naturally Fractured Heavy Oil Reservoirs: a Case Study

Abstract: Steam injection process has been considered for a long time as an effective method to exploit heavy oil resources. Over the last decades, Steam Assisted Gravity Drainage (SAGD) has been proved as one of the best steam injection methods for recovery of unconventional oil resources. Recently, Fast-SAGD, a modification of the SAGD process, makes use of additional single horizontal wells alongside the SAGD well pair to expand the steam chamber laterally. This method uses fewer wells and reduces the operational cost compared to a SAGD operation requiring paired parallel wells one above the other. The efficiency of this new method in naturally fractured reservoir is not well understood. Furthermore, how operational parameters could affect the efficiency of this method is a topic of debate. In this study, Fast-SAGD is compared through numerical reservoir simulations with standard SAGD in an Iranian naturally fractured heavy oil reservoir and additionally some operational parameters including initiating time of steam injection in offset well, number of cycles assuming the same total period of steam injection, offset injection pressure, elevation of offset well from the bottom of reservoir and vertical distance of production and injection SAGD well pairs have been evaluated in Fast-SAGD process. The operational parameters have been optimized based on Recovery Factor (RF) and economical points. The results of this study demonstrated the exceptional performance of Fast-SAGD process in naturally fractured reservoirs and the RFand thermal efficiency of Fast SAGD are enhanced tremendously comparsed to SAGD. In addition, the results indicated that the most important parameters that should be optimized before Fast-SAGD is initiating time of steam injection in offset wells. This study reveals improved efficiency and lower extracting costs for heavy oil in naturally fractured reservoirs applying FastSAGD process. Also it is indicated that optimization of operational parameters significantly improves Fast-SAGD performance in such reservoirs.

Determination of the optimum temperatures and mass ratios of steam injected into turbocharged internal combustion engines

Abstract: Water injection method into the internal combustion engines is commonly used to improve performance and emissions. However, condensed water causes to deteriorate the lubrication oil, in-cylinder corrosion is carried out and also wear rate of moving parts of engine increases. In order to prevent this bad effect of condensed water, steam injection is proposed. Electronically controlled steam injected method has been used for naturally aspirated engines and successful results have been obtained in terms of performance and NOx emissions. However, supercharged engine systems are used in practical life. In this study, steam injection method is developed for turbocharged systems. The optimum temperatures and mass ratios are determined based on thermo dynamical analyses.

The Use of a Nano-nickel Catalyst for Upgrading Extra-heavy Oil by an Aquathermolysis Treatment Under Steam Injection Conditions

Abstract: Nano-nickel catalyst was prepared in microemulsion system, and used in the viscosity reduction process of extra-heavy oil by aquathermolysis. The results showed that the nano-nickel had a good catalytic performance in the aquathermolysis, and the viscosity of extra-heavy oil San56-13-19 was reduced by 90.36% at 200°C. The structure and group composition of the heavy oil were tested and analyzed by thin-layer chromatography-flame ionization detection, Fourier transform infrared spectroscopy, elemental analysis, vapor phase osmometer, and hydrogen-1 nuclear magnetic resonance before and after the aquathermolysis. It was found that the pyrolysis of asphaltene played a key role in viscosity reduction, and the O-containing products such as alcohol, carboxylate, and fatty acid can reduce the viscosity of heavy oil during the catalytic aquathermolysis.

An Enhanced Oil Recovery Technology as a Follow Up to Cold Heavy Oil Production with Sand

Abstract: Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. Cold Heavy Oil Production with Sand (CHOPS) has been successfully implemented in these reservoirs. However, primary recovery is still low averaging below 10%. How to economically recover the large amount of remaining oil in place is a challenge. Therefore, an effective follow up recovery process is required. Steam injection technologies cannot be widely applied because most of the Lloydminster heavy oil reservoirs are thin and the heat losses to overburden and underburden make the process uneconomic. Alternative solvent methods are not commercial yet due to uncertain oil recovery rates and low solvent recovery. Hybrid application of the aforementioned two technologies using hot water together with solvents could be an economic post-CHOPS recovery process. The wormholes created during the primary recovery can be used to contact large reservoir volumes with hot water and solvent. This paper contains the results of hot water and solvent oil recovery experiments conducted in preserved heavy oil cores. Experimental work consisted of three phases. Cores were immersed in hot water in the first phase to pre-heat the formation. Next, cores were exposed to n-heptane as hydrocarbon solvent. Finally, cores were immersed in hot water again to recover the oil as well as the solvent. The ultimate oil recoveries varied between 42% and 88% OOIP and, the asphaltene precipitation varied between 2.5 wt% and 11.7 wt%. Experiments were also carried out with a distillate from Husky’s Lloydminster upgrader used for heavy oil transportation in the pipelines. Better results were obtained if the distillate was used instead of the pure hydrocarbon solvent. It was observed that oil recovery at the end of the initial hot water injection phase due to thermal expansion and viscosity reduction was negligible compared to the ultimate recovery. However, the first phase serves to condition the reservoir for better diffusion in the second phase when the solvent is injected. The final phase of hot water injection causes the water to strongly imbibe into the matrix enhancing the oil and the solvent recovery.