Knowledge of fluid properties is critical to the design of Vapex projects and other enhanced oil recovery processes that use solvent vapor extraction, yet very few pertinent data exist in the published literature. This paper describes a new apparatus for the efficient and accurate measurement of the physical and phase behaviour properties of mixtures of heavy oils and solvents such as propane and butane. The apparatus combines advanced capabilities that make it superior to conventional designs: The automated functions improve the speed at which the data are acquired and reduce operator error. Inline density and viscosity measurements add the capability of multi-phase detection. High-pressure filtration permits measurement of asphaltene and wax precipitation at reservoir conditions. Dual gasometers allow accurate measurements of gas solubility over a wide range of solvents and reservoir pressures. Sub-ambient temperature control makes it suitable for Canadian operations.
The apparatus was tested against published measurements for the n-hexadecane-carbon dioxide system, and then used to gather a comprehensive suite of data at two isotherms for a Lloydminster heavy oil-propane system. Random scatter in the resulting data was very small.The equipment is well suited to the acquisition of fluid property measurements for both field design and correlation purposes.
With the improvements in both the precision of measurements and the speed of operation offered by the new equipment, it was possible to test some assumptions used in measuring vapor-liquid equilibrium in heavy oil-solvent systems.The results suggested that a noticeable uncertainty may be associated with conventional methods used to determine saturation pressures in these systems.
Production of extra heavy oil or bitumen by means of SAGD (Steam Assisted Gravity Drainage) requires the generation and injection into the reservoir of a great quantity of steam. A corresponding quantity of hot water is then produced along with the mobilised oil. Bearing in mind existing and future environmental regulations, it is likely that partial or even total recycling of this produced water back into steam will become mandatory.
The complexity of thewater treatment scheme required depends on the water characteristics, the steam boiler specification (OTSG or conventional 100% steam boiler) and whether or notwaste water disposal is completely eliminated (zero reject) or not. SAGD developments have some specific water treatment issues which need to be addressed, for example the high silica content of the produced water.
This paper will present different conceptual designs for a 300 000 bwpd water treatment plant. The different schemes discussed include an OTSG boiler, a conventional boiler and the zero disposal option. The various options available for process equipment will be presented, together with two different salinities of produced water and their impact on process design. Included will be an evaluation of capital cost and operating costs elements.
As a result of hydrothermal stress induced by steam injection in reservoirs, heavy crudes undergo chemical transformations, called aquathermolysis, the extent of which depends at least on steam temperature, injection history and both crude and mineral matrix physicochemical properties. As heavy crudes often have high sulfur content, their hydrothermal alteration results in the formation of H2S. In order to predict artificial H2S emissions during thermal EOR, we seek to develop a geochemical model to be coupled with a 3D reservoir simulator.
This paper presents the first step of the process that consists in simulating in-situ aquathermoysis in laboratory in order to derive a 0D compositional kinetic model for H2S formation.
For that purpose, aquathermolysis experiments were performed on an Athabasca oil sand sample. The amount of H2S generated during aquathermolysis was measured for different time and temperature conditions. At the same time, sulfur distribution was quantified over crude SARA fractions (Saturates, Aromatics, Resins and Asphaltenes) and insoluble fraction (mainly mineral), before and after aquathermolysis. Experimental results were then derived to elaborate a kinetic model of H2S generation upon aquathermolysis, encompassing the chemical conversion of sulfur in SARA and insoluble fractions.
Steam and hot water assisted recovery from heavy oil reservoirs can induce physicochemical interactions between water, oil and rock. As a result, significant amounts of hydrogen sulfide, together with carbon dioxide, may be generated, increasing the risk of corrosion, health security problems and environmental aggression during production (Burger et al., 1985; Mohammed et al., 1990; Thimm, 2001).
Aquathermolysis is defined as the sum chemical reactions between heavy oil and steam (Hyne et al., 1984; Hoffman et al., 1995). Aquathermolysis laboratory experiments were previously carried out, either on isolated heavy crude (Hyne and Clark, 1981), or on whole core samples (Akstinat, 1983; Hyne et al., 1984; Attar et al., 1984; Monin and Audibert, 1988; Hoffman and Steinfatt, 1993; Belgrave et al., 1994; Pahlavan and Rafiqul, 1995). These studies emphasized the importance of aquathermolysis as a source of H2S during steam and hot water injection. This process may be quite efficient for temperatures higher than 200°C at production time scale. Moreover, H2S yields and formation rates appeared to depend merely upon the amount and the nature of organic sulfur compounds in heavy oil (Hyne et al., 1984; Attar et al., 1984; Lamoureux-Var and Lorant, 2005). This latter observation suggests that, as a first approximation, the H2S potential of a reservoir rock submitted to steam injection might be correlated to the content of the most hydrothermally labile sulfur compounds in the reservoir. Assuming these compounds might be contained in specific fractions of the oil sand, the aim of this work was:
1/ to assess which fraction(s) of the oil sand (SARA + insoluble) might be the source(s) of H2S;
2/ from this assessment, to correlate H2S generation to sulfur distribution over the source fractions, via a kinetic formulation.
Using recent results from fine-scale, multi-pattern, geostatistical models of the Kern River field, California, this paper reviews key issues related to steamflood modeling and shows that fine-grid models depict the near-vertical steam override, and corroborates that heavy oil steamflooding is not a displacement process; rather the oil drains by gravity. Further, models with unconfined boundaries result in steam zone pressures similar to those observed in field.Including the common operating practice of cyclic steaming of producers at early time reduces pressures and accelerates steam breakthrough time and recovery.
Furthermore, pattern element and single sand models used in many previous studies are not sufficient to explain observed field performance, and that larger, heterogeneous model give more realistic recovery predictions. Discontinuous shales allow significant drainage to occur from the upper to the lower sands. Consequently, the upper zones may contain less reserve than expected and the lower zones can give apparent high recovery.Use of parallel models showed significant speed up over serial models allowing significantly larger models to be run in a reasonable time.Apparent higher speed up is gained for larger models.
The paper demonstrates that the current improvements make larger-scale modeling of steamflood projects viable compared with what was possible earlier and that a realistic forecast of steamflood performance is attained when the necessary details are included in the model.
Steam injection is the most widely applied enhanced oil recovery (EOR) method.[1-6] Current oil production by steam injection is estimated to be over 1.1 million BOPD.Most conventional heavy oil steamflooding projects in California, Canada, Indonesia and Venezuela employ vertical wells; although, the use of horizontal producers is growing.[5,6] On the other hand, extra heavy oils may require both horizontal injectors and producers, such as, steam assisted gravity drainage (SAGD).Oil recovery can exceed 20% of the original oil in place (OOIP) for cyclic steaming and over 50% OOIP by continuous steam injection (for small well spacing).[2,4-6]
Early steamflood performance prediction methods used analytical and semi-analytical models,[7-8] that did not account for gravity override of steam.Later, Neuman9 developed an analytical gravity override model for steamdrive. The analytical models are heat flow and energy balance models with an assumed shape of the steam zone and uniform properties; therefore, they can not account for the effects of variation in geology, fluid property, and operating conditions.Scaled-physical models were used as improvement over the early analytical models.[2,10,11]Although, the scaled models portray most mechanisms accurately, they are time consuming and cumbersome.Further, they may be limited by availability of materials and fluids to achieve proper scaling of a particular reservoir and oil..Consequently, they are seldom used now as a forecasting tool.
The Christina Lake Thermal Project, located 170 km South of Fort McMurray, Alberta, uses steam-assisted gravity drainage (SAGD) technology to recover bitumen from the McMurray formation.The bitumen reservoir at Christina Lake is approximately 400m deep, and is delineated by over 300 vertical wells and extensive 3D seismic coverage. The McMurray formation can be informally subdivided into three units - Lower, Middle and Upper. The Middle unit contains the major bitumen bearing reservoir, while the Lower unit is generally water bearing and the Upper unit typically contains gas with some residual bitumen saturation. SAGD at Christina Lake was first implemented in 2001 (Phase 1, Figure 1). The currently developed project area is covered by time-lapse surface 3D seismic and crosswell seismic.
The 3D survey was acquired using mega-bin geometry, with a bin size of 12.5 m by 12.5 m. A baseline survey was conducted in 2001 followed by two repeat surveys in 2004 and 2005.In addition, six crosswell seismic profiles were acquired by placing both sources and receivers in vertical wellbores. The goal of the survey is to better understand reservoir architecture by detecting lithology changes, including predicting the occurrence of mudstone stringers and their lateral and vertical distribution. Crosswell seismic data in this project have provided about one metre vertical resolution in the McMurray Formation, detectedmudstone stringers, and indicated significant reservoir heterogeneity, all of which helped to more accurately characterize the reservoir and better predict reservoir performance under thermal operations. Results of the six profiles provide encouraging insight into the potential of crosswell seismic technology. Although there is a needfor future research in several areas, crosswell seismic has the potential to complement and enhance the interpretation of surface 3D seismic.
Analysis of both 4D and crosswell data showed that steam chamber growth and oil recovery are strongly influenced by reservoir geology.Steam chamber growth is especially affected by the presence of low permeability facies in the vicinity of the SAGD well pairs. In each case to date, less than 100% of the well length contributes to oil production.These findings have significant impacts on the planning of future developments.
In this study, a particular hybrid process with propane and steamco-injected is simulated numerically under different operation strategies. Theroles of propane in the hybrid process are investigated. The economics of thesehybrid processes are also evaluated with a supply cost model. Results show thathybrid processes with steam and propane co-injection can have the same supplycost as that of SAGD process and propane-related cost is a small part of thetotal supply cost in these hybrid processes due to the small amount of propaneused in this study. Results also show that low pressure hybrid processes aremore cost-efficient than their high pressure counterparts.
Giant, geologically complex heavy oil fields can take decades to develop, sodevelopment decisions made early in the life of the field can have long-rangeimplications.Decision and risk analysis (D&RA) is often used to makedecisions that will maximize risk-adjusted economic benefit.Unfortunatelyin large heavy oil fields, D&RA can be very challenging due to the largenumber of variables and the endless number of development and expansionscenarios to analyze.The time needed to complete a D&RA can becomeprohibitive when full-field reservoir simulation is the main tool forforecasting primary production and well count, with one simulation taking manyhours or days to complete.
This paper describes two new simulation tools developed to overcome thesechallenges: 1) a method for populating a model with hundreds-to-thousands ofhorizontal wells, and 2) a method to quickly and directly optimize expansiondecisions.
A semi-automated spreadsheet-and-simulation method was developed to quicklyplace and select hundreds-to-thousands of hypothetical/future horizontal wellsin a multi-million grid- block model.Because the method automaticallyaccounted for all model static properties and their effects on dynamicproduction response, the hypothetical wells had productivity characteristicsvery similar to actual drilled wells placed in the model.
A multi-variant non-linear interpolation method was developed that enabledfull-field forecasts - for any combination of acreage allocation, well count,drilling order, and expansion rate constraint - to be calculated in less than 5seconds, compared to about 20 hours for traditional simulation.Extensivevalidation work showed that well count and production curves from thespreadsheet virtually overlaid those obtained using traditional simulation ofthe particular expansion scenario.Such close agreement was possiblebecause the basis of the spreadsheet forecast was utilization of traditionalsimulation forecasts from a handful of relevant cases.
A key breakthrough beyond just fast forecasting was the coupling of thefollowing three components inside the same spreadsheet: the fast forecastingmethod, calculation of an economic indicator/objective function (NPV), andcommercial optimization tools.This linkage made possible, perhaps for thefirst time (at least at this scale), realization of direct optimization of anydevelopment scenario in a matter of minutes to a few hours, depending on thenumber of variables being optimized.
Fresh water scarcity and increasing demand are worldwide concerns and arebeing addressed by a number of water man-agement initiatives in Alberta andCanada.In 2003, 0.3 bil-lion m3 of produced water was injected intodisposal wells associated with oil and gas production in Alberta.Thisvol-ume of water is a potential resource for recycling and benefi-cial reuse inAlberta, which would have a significant impact on sustainable development inAlberta. This water must first be treated to meet water qualityrequirements and regulatory guidelines for specific applications.Thispaper provides a comprehensive technical and economic review of watertreat-ment technologies and shows that water treatment processes arecommercially available.Although the cost of implement-ing suitabletreating processes to meet drinking water quality guideline is estimated atthree times the current cost of mu-nicipal water supply in Alberta, it is morefeasible to recycle produced water for other purposes, such as agricultural orpe-troleum application (i.e., waterflooding, etc.).This is because waterquality guidelines for most other applications are not as stringent as that fordrinking water and there is increasing pub-lic resistance for industry to usefresh water for commercial applications. A multi-disciplinary researchand development team studying water recycle and beneficial reuse is necessaryto look into these issues. The University of Calgary is set tocollaborate on such projects due to the current research em-phasis onsustainable energy and environmental impact. Col-laboration between thegovernment, industry and academia to develop initiatives aimed at reducingfresh water is possible in Calgary for several reasons.One is theproximity of many major oil and gas companies in this city, which would allowfor easy communication.Another is the fact that the current price of oilwould not inhibit producing companies from in-vesting in this kind ofresearch.The result can be well-developed initiatives to treat andrecycle produced water for beneficial reuse, thus reducing fresh water demandfor many applications in the petroleum and agricultural industries.
A steam chamber generally rises steadily in the channel sands of Athabascaoil sands during a SAGD operation.It is commonly known that steam chambergrowth rate is mainly dependent to permeability.Once the steam chamberreaches the upper boundary, it starts to expand laterally.This is thebasic concept of steam chamber growth of SAGD process in fine sands.
However, the growth of steam chamber measured through the analysis oftemperature changes from observation wells behaves different in many instancesthan the commonly accepted steam chamber growth concept, explainedabove.In these observation wells, the steam chamber deviates from theusual behavior; sometimes stops and then resumes rising or shrinking, or evendisappears during SAGD process.This can be caused by the specific natureof steam fingering phenomenon during SAGD operation.
Many simulation studies have been conducted to understand the steam risingphenomenon during SAGD operations.At the top of the steam chamber, steamfingers seemed to be created where steam flows through and the steam chamberexpands vertically.If steam fingering actively develops, steam chambergrows steadily as expected.However, activity of fingering can bedisturbed under certain conditions, which can result in various alterations inthe growth of steam chamber.
In this paper, the steam fingering phenomenon during SAGD process isdiscussed with actual measured field data from four SAGD projects; UTF Phase A,UTF Phase B, Hangingstone and Surmount.
In this work, the vapour extraction (VAPEX) process was studied in a multiple block, dual porosity fractured system. The performance of this process is compared with a conventional, non-fractured system under similar rock and fluid properties, bulk volume, pore volume, hydrocarbon volume, and injected pore volume of solvent and solvent injection rate. At early stages of the VAPEX process in fractured system, the solvent-oil interfaces form and develop from all sides of the matrix, and the oil chamber, rather than solvent chamber forms and shrinks in the center of each block. Also, at later stages of the process, the solvent zones from all neighboring blocks combine and form an integrated solvent zone, which is similar to that in the conventional systems.
The results showed that in low-permeability carbonate reservoirs, the fracture network provides communications for solvent flow through which the solvent can flow faster and form solvent fingers at early stages, which can reach the blocks located at farther distances from injection well. It was found that the solvent breakthrough starts at he same time in both low-permeability non-fractured system and fractured system. This is because the solvent flows directly through drained areas towards producer in both systems.
Further, effect of solvent injection rate on heavy oil recovery in the fractured system was studied in two cases: different injection rate at the same injection time, and different injection rate with the same injected pore volume. It was found that the solvent injection rate should be optimized for a specific system in order to control the solvent breakthrough and to avoid extra operation time and cost.