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Collaborating Authors
SPE International Thermal Operations and Heavy Oil Symposium
Abstract Incursion of subterranean tar into the wellbore during and/or after drilling has the potential to result in a variety of problems. If the tar is soft and deformable, it may ‘refill’ the wellbore and require additional drilling time and casing operations. An additional problem is adhesion or accretion of the tar directly onto the drillstring or bottom-hole-assembly (BHA). Such fouling of the drillstring/BHA often requires unplanned tripping to physically remove the adhered tar. It is also conceivable that the tar-related problems may ultimately result in the hole being plugged and abandoned. For these reasons, an approach has been developed toemulate the reported wellbore accretion, and develop lab-based approaches to help minimize/reverse the tar adhesion. Investigation of tar accretion onto steel rods/tubes with a Gulf of Mexico tar was studied in a synthetic-based mud, to evaluate possible avenues of remediation. In addition to evaluating the conditions necessary to induce tar accretion in the laboratory, further studies were performed to affect reversal of the intentional accretion and also to help prevent initial accretion. Included are the results from the induced accretion and various additive-based attempts to mitigate the tar adhesion. In order to induce lab-based accretion, it proved necessary to develop a testing method to emulate the scope of tar accretion observed in the field. This methodology is herein described along with the optimized fluid system. Of specific interest in this study is the ability to use this novel fluid either as a sweep, spot or additive as a means to help reduce the inherent ‘tackiness’ of the tar and thereby help reduce/prevent the adhesion to the emulated drill string. The fluid treatment developed is environmentally acceptable and uses a novel chemical composition which proved successful in reversing and preventing tar accretion under the laboratory experimental parameters. Introduction There is a significant amount of inconsistency present in the literature for the terminology of these native highly-viscous subterranean petroleum heavy fractions, often interchangeably using the following terms; bitumen, asphalt, tar, oil-sands, tar-sands, and heavy-oil. Although regional preferences appear commonplace, the most encompassing term to describe the material is; bitumen. Bitumens are composed of the same four classes of materials found in crude oil, ‘Saturates’, ‘Aromatics’, ‘Resins’, and ‘Asphaltenes’ (SARA), however, it is the exceptionally high concentration of flocculated asphaltenes, that result in the troublesome high-viscosity material.[1–5]For this reason, the bulk properties of a specific bitumen sample are largely dependent on the characteristic resin and asphaltene concentrations and samples from different regions should not be assumed to be analogous.6 Traditionally, the components of a bitumen were categorized based upon solubility/insolubility properties using a variety of solvency schemes.[1]In one current solvent-classification scheme, the asphaltene fraction of a bitumen is defined as the precipitated insoluble material obtained from a dispersion in n-hexane.[7]Regardless of the name applied to the material, it poses substantial problems to drilling operations in the form of a highly-adhesive wellbore contaminant. The two primary concerns for drilling in/through a bituminous zone aremanagement of the highly adhesive cuttings displaced by the drilling operation and minimizing the tendency of the wellbore to deform and even potentially reseal. The objectives of the bitumen drilling operation differ based upon the type of well in question,a deepwater well where a bitumen zone is encountered while drilling to a target formation or an oil-sands region where a series of wells are intended to be specifically drilled within the bitumen zone for production purposes.8 In both of these cases, the drilling operation would ideally drill through the sticky material with minimal non-productive time and the cuttings would be conventionally managed by the drilling fluid and the surface equipment. In the case of oil-sands drilling, it is additionally desired that the wellbore remain a gauge hole for suitable time for later insertion of the production screens.
- North America > United States (0.67)
- North America > Canada (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.88)
Abstract 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. Introduction 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.[1]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).[5]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.[2]. Consequently, they are seldom used now as a forecasting tool.
- North America > United States > California > Kern County (0.50)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.26)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.90)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Webster Formation (0.99)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Monterey Formation (0.99)
- North America > United States > California > San Joaquin Basin > Kern River Field (0.99)
The Stimulation Technology Research and Application in the Heavy Oil Carbonate Reservoir of the Fracture and Cavity
Guo, Jianchun (Southwest Petroleum Institute) | Zhao, Jinzhou (Southwest Petroleum Institute) | Chen, Lingming (Northwest Petroleum Bureau of Sinopec) | Li, Yomgming (Southwest Petroleum Institute) | Fu, Ying (Southwest Petroleum Institute)
Abstract The Ordovician carbonate reservoir in Taliram Basin is typical of fractured and caved reservoirs with thick oil layer, high temperature, deep zone and extra heterogeneity together with high density, high viscosity and high freezing point et al as common characteristics of crude oil. More than 80% wells have to be stimulated before economically producing. Based on the laboratory researches and plentiful field practices, the following stimulation modes are formed: the multiplayer acid-fracturing for long open-hole interval or layered acid-fracturing, height-control acid-fracturing against bottom water coining, a combination of hydraulic fracturing and acid fracturing. On the basis of drill so&g, logging data, well-recorded data and some geophysical data such as change rate of logging amplitude, cohere body and Jason reversion et al., model for well selecting and layer appraising is developed. We develop high-visco gelling acid, retarded acid based on surfactant, low friction resistance emulsified acid as well as insitu stiffening acid, with better retardancy, low leakage and low friction as the result, with which the damage near the wellbore is effectively solved and deeply penetrated acid-etched fracture is obtained. Furthermore, the 3D acid fracturing optimization design techniques for fractured and caved reservoir brought forward in this paper have accurately calculated the treatment data and fracture geometry, thus the effectiveness of acid fracturing is increased a lot. Up to the end of 2003, more than 220 times of application of acid-fracturing in Ordovician Carbonate Reservoir of Tahe Oilfield located in the northeast of Taliram Basin of China have indicated that 98.8% were effective, with average single-well incremental yield of 60t/d and the period of validity over 250 days, therefore, Tahe oilfield has increased the production about 311.8×10[4]t altogether. Introduction Tahe Oilfield, which lies in Kuche and Luntai County of Xinjiang, China, is a large marine carbonate reservoir found by Sinopec. This Ordovician reservoir, with depth of 5400∼6300m, is characteristic of large layer span, strong heterogeneity, high reservoir temperature above 120°C and high oil viscosity et al. Many wells are of low nature yield and well stimulation is a key technique for both high yield and steady production. Considering characteristics of the geology and stimulation technology, suitable acid-fracturing for deep well and large interval of Tahe oilfield is recommended, based on the synthetical researches on stimulation technology, acid-fracturing design model and acid system. Retarded acid system with high viscosity and low friction is developed and a novel leakoff model for fractured and caved reservoir is established. Coresponding matched wellbore production technology is also presented. In this paper, all of the above are described as well as their successful application in Tahe Oilfield. Characteristics of Reservior Geology and Fluid Tahe oilfield is located in the southwest of Akeku Pimpling in Shaya Hunch in Taliram Basin, where Triassic, Carboniferous and Ordovician formation show good oil&gas. The combo, with reservoir bed of Lower Ordovician karst f fractured and caved reservoir and capping bed of Upper Carboniferous mudstone, is one of most primary ones. Ordovician formation, controlled by noselike Akekule Pimpling and laterally by compact carbonatite, belongs to unconformable fracture-aperture combination trap. Up to October 2004, in Ordovician formation of Tahe Oilfield, Blocks 2, 3, 4, 6, 7 and 8 have been proven up, with the superposition areaof 381.1km2 and OIP ofover 2×10[8]t.
- Geology > Rock Type > Sedimentary Rock (0.86)
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.41)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- North America > Mexico > Veracruz > Veracruz Basin (0.99)
- North America > Mexico > Gulf of Mexico > Veracruz Basin (0.99)
- (2 more...)
Abstract SINCOR is one of the major operators of the Orinoco Belt in Venezuela (Figure 1). It produces 8.5°API gravity of Extra Heavy Oil (EHO) with a viscosity at reservoir conditions between 1800- 3500cP. The EHO is upgraded in Venezuela to market of high quality 32 °API synthetic crude oil. The geological context is fluvio-deltaic with high sand content, very good permeabilities and large regional aquifer. Before start-up, the impact and strength of the aquifer were identified as major risks for both production and reserves due to extreme viscosity contrasts. The first phase of development is completed and includes more than 300 horizontal wells. SINCOR produces 200.000 bbl EHO/d today. Prior to a second development phase, answering to the question: "what have we learnt of the aquifer risk?", should help making the next development phase more efficient. Some of the main lessons learnt are:Water entry is very local in the wells. Risk of water interference between wells in the same sand is high. Wells accumulate large volumes of EHO after water breakthrough. Aquifer pressure support is lower than expected. Thorough monitoring policy of wet wells allowed evidencing some specific characteristics of this EHO field:Water banking at well level. Link liquid rate/water cut...favorable to EHO. Data acquisition allowing partial quantification of aquifer strength. A production policy was then implemented that allowed optimizing both production potential and reserves of existing wells. To maximize reserves, water handling capacity (WHC) is adjusted with time and the future drilling sequence will account for both planned WHC modifications and risks of water interference. Phased development coupled with thorough monitoring policy lead to understand better the behavior of EHO crude in unfavorable environment. Today, this allows SINCOR to adapt its development plan to improved control of the risks linked to the aquifer. This paper demonstrates the added value of an appropriate integrated monitoring strategy that optimizes reservoir performance and provides lessons for further development plans. Introduction SINCOR is a strategic association between PDVSA, TOTAL and STATOIL, developing extra heavy oil in Zuata field which is located in Eastern Venezuela. Approximately, 80% of its producers are drilled in fluvial sands characterized by water production risks. In contrast, deltaic sands represent 20% of total oil production with little or no water risk. Due to extreme viscosity contrasts, after breakthrough the water cut in many wells increases rapidly. The produced water is injected into the Lower Oficina aquifer through disposal wells. The growing water production is gradually becoming a bottleneck for surface production facilities. In 2001, the water handling capacity was limited at 20.000 bwpd, so most of the watered out wells were shut in. After 3 years of production, the capacity was increased to 40.000 bwpd. Since 2005, the water capacity reached 70.000 bwpd giving flexibility to produce more watered out wells (Figure 2).
- South America > Venezuela > Orinoco Oil Belt > Eastern Venezuela Basin > Zuata Field (0.99)
- South America > Venezuela > North Atlantic Ocean > Eastern Venezuela Basin (0.99)
- South America > Venezuela > Eastern Venezuela Basin > Oficina Formation (0.99)
- South America > Venezuela > Orinoco Oil Belt > Eastern Venezuela Basin > Sincor Field (0.98)
Abstract The production of extra heavy oil (or bitumen) through the SAGD method (Steam Assisted Gravity Drainage) requires the generation and injection into the reservoir of a great quantity of steam. A typical value of the steam/oil ratio is around 3, which means that a 100,000 bopd development requires the injection of 300,000 bcwepd (barrels of cold water equivalent per day) of steam, and that a corresponding quantity of hot water will be co- produced with the oil. The production of extra heavy oil containing many active components with the tendency to form an emulsion combined with the high water-cut ratio (above 80%) leads to a phase separation process with specific issues. This study considers an extra heavy oil field produced in SAGD in Athabasca. The objective of the study was firstly to characterise the produced fluids and then to analyse their tendency to form an emulsion under controlled hydrodynamic conditions. An innovative technique - Differential Scanning Calorimeter (DSC) - was used to characterise the emulsion. This method is able to define the water-in-oil or reverse emulsion nature and to quantify the water amount without sample dilution. DSC analysis combined with microscopy and image analysis treatments was used to determine the droplet size distribution. Reconstituted emulsions were then formed using a "Dispersion Rig" set-up that allows the simultaneous pumping of crude oil and water through a calibrated restriction in the pipe. The amount of energy dissipated to the fluids systems can be quantified due to the strict control of the hydrodynamic conditions. Consequently a relationship between granulometry distribution of the emulsion and the fixed energy or pressure drop can be established. The main experimental parameters investigated were the oil dilution and water-cut ratios. It is concluded that there is a residual emulsion in extra heavy oil which has a very small average droplet size whatever the temperature and solvent dilution ratio. This small droplet size results in a difficult oil/water separation which is only possible either by addition of large quantities of additives at high temperature and with long residence time and probably by applying an electrostatic field. Introduction Albertan oil sand deposits contain an estimated 1.7 trillion barrels of oil of which 300 billion barrels are believed to be recoverable by surface mining or insitu developments. One of the insitu technologies which is used in several Athabascan developments is Steam Assisted Gravity Drainage (SAGD), this extraction technique injects steam continually adding energy and heating the reservoir. This injection produces a steam chamber within the reservoir enabling Extra Heavy Oil to be produced together with hot water back to surface via a production well. SAGD requires substantial quantities of steam. A typical steam/oil ratio is in the order of 3 barrels of water equivalent of steam per barrel of bitumen produced. This steam is then co produced in a multiphase mixture with the bitumen. This multiphase mixture must be separated to provide a dehydrated oil stream which may be transported for further downstream processing or upgraded on site. This water and oil mixture contains active components that promote emulsion formation. This tendency to form emulsions coupled to the produced fluids high water cut makes separation difficult to achieve. So that that this separation system can be adequately specified it is essential that the emulsion is characterized. This paper sets out the techniques used to characterise an Athabascan oil field emulsion, the equipment used to form the emulsion in the laboratory and then discusses the results of this characterisation. This paper sets out a methodology used to characterize and study the behaviour of emulsion produced from an Athabascan SAGD development.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
Geostatistical Modeling Integral to Effective Design and Evaluation of SAGD Processes of an Athabasca Oilsands Reservoir, A Case Study.
Robinson, Bill (Paramount Resources) | Kenny, Joseph (Atech Application Technology) | Hernandez-Hdez, Ivan Lazaro (Atech Application Technology) | Bernal, Jeimy Andrea (Roxar Inc.) | Chelak, Rob (Roxar Canada)
Abstract The design and implementation of a successful thermal recovery project starts with a representative static geological model. SAGD operating strategies of the steam chamber for optimum economical oil recovery with minimum SOR are largely controlled by the target reservoir geological and pressure environment. This paper describes how geostatistical modeling techniques were used to build a static reservoir model over a 32-section area of a Fort McMurray oil sand reservoir. The model was constructed by using Roxar's Irap RMS modeling software. Irap RMS provided a platform that facilitated geostatistical mapping of horizons and populating the petrophysical properties over a 3.46 million cell static geological model. This paper describes how the petrophysical logs and core data from 33 wells in the study area were integrated into a coherent geostatistically based geological model from which any number of equiprobable realizations of the geological environment may be drawn. The large scale geological model was built so that the impact of regional variability of reservoir quality on SAGD process strategies could be evaluated, optimized and readily assessed by using dynamic simulation techniques and by extracting and appropriately upscaling portions of the static reservoir model. This modeling strategy also allows risk analysis of geological uncertainty at a given location on SAGD performance to be evaluated by conducting and analyzing multiple dynamic simulation runs generated from equiprobable realizations of the static geological model. The use of geostatistical techniques to assess data quality and impact of geological uncertainty on the geological description are reviewed. The impact of this uncertainty on quantification of bitumen in place and its impact on establishing and prioritizing the placement of well pairs are also presented. A review of the geology and the workflow followed by integrating petrophysics, core data, mapping of horizons, and rock types are discussed. The extraction and upscaling process used to create the dynamic simulation is described. The workflow strategy that was adopted allowed the definition and evaluation of SAGD operating strategies across the field to be evaluated concurrently and quickly with representative dynamic simulation models of a reasonable size. Introduction The Athabasca oil sands deposit contains 136,926 × 106 m3 of bitumen in place with only 17,998 × 106 m3 potentially surface-mineable (EUB Statistical Series 2004–98). The bulk of this resource must be accessed through in situ means, which at this time is primarily SAGD. In order to properly exploit this resource it is necessary to develop a geological framework, which can be used to predict performance and plan optimization strategies. In support of a Fort McMurray's Steam Assisted Multi-Well Pair Gravity Drainage project a geostatistically based geological model over 32 sections of the McMurray oil sands was prepared. The geological model provided a platform from which dynamic simulation models were extracted in order to assess the impact of geological variability on the operating strategy of the SAGD process over a 12 year forecast period The geological model was built by using Roxar's Irap RMS geostatistical modeling package, which has workflow management, allowing the user to integrate input data and procedures followed and keep the project documented at all times. The workflow is available within a single visualization environment with access to a full range of common tools, including data import/export, data analysisand quality control (QC), as well as volumetric analysis. This tool facilitated the building of a modeling sequence, which ensured repeatability and rapid update of new and modified input data. By using this tool it was possible to easily make systematic geological and geophysical variations in modeling parameters, and quickly update the model accordingly. This was done in a batch process, offering an easy way to quantify the sensitivity of the investigated parameters. Figure 1 shows a simplified workflow to construct, populate, and upscale the geological model.
- North America > Canada > Alberta > Census Division No. 16 > Regional Municipality of Wood Buffalo > Fort McMurray (0.44)
- North America > Canada > Alberta > Athabasca Oil Sands (0.24)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Beaverhill Lake Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.98)
- (5 more...)
Abstract Steam-Assisted Gravity Drainage (SAGD) is being operated by several operators in Athabasca and Cold Lake reservoirs in Central and Northern Alberta. In this process, steam, injected into a horizontal well, flows outwards, contacts and loses its latent heat to bitumen at the edge of a depletion chamber. As a consequence, the viscosity of the bitumen falls, its mobility rises, and it flows under the action of gravity towards a horizontal production well located several meters below and parallel to the injection well. In practice, the temperature difference between the injected steam and produced fluids, called the subcool, is maintained between 15 and 30″C. Despite many pilots and commercial operations, it remains unclear what the impact of subcool on the performance and thermal efficiency of SAGD especially in reservoirs with a top gas zone. The objective of this study was to define a steam chamber operating strategy that leads to optimum oil recovery for minimum cumulative steam to oil ratio in a reservoir with a top gas zone. These findings were established from extensive simulation runs that were built from a detailed geostatistically generated static reservoir model. The strategy devised uses a high initial chamber injection rate and pressure prior to chamber contact with the top gas. Subsequent to breakthrough of the chamber into the gas cap zone, the chamber injection rates are lowered to balance pressures with the top gas and avoid or at least minimize convective heat losses of steam to the top gas zone. The results are also analyzed by examining the energetics of SAGD. Introduction A cross-section of the Steam-Assisted Gravity Drainage (SAGD) process is displayed in Figure 1. Steam is injected into the formation through a horizontal well. In Figure 1, the wells are portrayed as points that extend into the page. Around and above the injection well, a steam depletion chamber grows. At the edge of the chamber, heated bitumen and (steam) condensate flow under the action of gravity to a production well typically placed between 5 and 10 m below and parallel to the injection well. Usually, the production well is located several meters above the base of pay. In industrial practice[1,2], injection and production wells lengths are typically between 500 and 1000 m. The injection pressure, because the steam chamber operates at saturation conditions, controls the operating temperature of SAGD.
- Geology > Rock Type (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
Abstract In West Central Saskatchewan the Mississippian/Devonian middle Bakken Formation was deposited as NE-SW trending sand ridges, capable of producing heavy oil. In the Court field, the middle Bakken sand pool has been operated as a heavy oil waterflood for over 15 years with significant success. A review of an earlier field simulation was conducted, an updated model generated, and the potential for reduction in well spacing has been identified. The lateral continuity of the sand ridge is variable due to post-depositional sinkholes. This structural complexity was mapped based on 3D seismic and well-logs and incorporated into the model. There were also stratigraphic disparities to take into account as discontinuous interbedded siltstones are potential flow barriers that create anisotropy in the permeability. Accordingly, grid orientation was modified to align axially with the main sand ridge permeability trends. Reservoir properties were re-assessed through correlation of cores, well-logs, porosity and permeability maps. Improved resolution was obtained with an increase in the amount of grid blocks used to account for the effect of grid orientation and numerical dispersion on the saturation distribution. A thorough analysis of pressure history, production/injection rates, waterflood performance by pattern interference, and dye injection tests were used to control the history matching process. The simulation model was then used to evaluate the downspacing potential and waterflood optimization of the middle Bakken reservoir. Introduction The Court field, located in west central Saskatchewan T33 R27 & R28 W3M, produces 17oAPI heavy crude from the middle Bakken Formation, using vertical wells and a waterflood recovery scheme. Improved understanding of the reservoir behavior is essential to continued field development and successful waterflood management. This paper documents the use of production and seismic data to update and substantiate a simulation model which was used to evaluate downspace potential. Geological Overview The Court field produces hydrocarbons from both the Bakken and Mannville Formations; this paper focuses on the middle Bakken sandstone reservoir. Bakken The Lower Mississippian Bakken Formation in the Court area is interpreted to have been deposited in a marine shelf environment and later reworked into tidally influenced sand ridges(1). Locally, the NE - SW trending sand ridges can reach 18m in thickness and are separated by narrow, tight inter-ridge areas that can be less than 2m thick. Structurally, the area has a relatively gentle SW regional dip. This has been modified post-depositionally by differential Prairie Evaporite salt solutioning and local collapse features of the underlying Torquay Formation's dolomitic limestones, characterized as sinkholes. Pre-Cretaceous erosion has cut down to or through the Bakken and oil was trapped stratigraphically by shale in the preserved Court middle Bakken sand trend. With the exception of local structural lows, the sands were entirely filled with oil. The same ridge trend contains the Court Unit and Court NE (collectively, the main pool) as well as Court SW, which was separated by erosion from the Court main pool. The land map for the area of interest is shown in Figure 1. The ridge appears to narrow and pinch out at the extreme edge of the Court NE pool. The middle Bakken sand is typically fine to very fine grained and composed almost entirely of quartz with minor amounts of feldspar and clay. It is commonly unconsolidated, although the base of the sand can contain a few meters of shaly, cemented, non-reservoir sediments that were probably the pre-cursor to the ridge itself. Minor, discontinuous shale interbeds may interrupt the vertical continuity of the reservoir sand. The arithmetic average intergranular porosity of Court was 29% while the permeability averages 2100 millidarcies. Initial water saturation was approximately 20%.
- North America > United States > North Dakota (1.00)
- North America > Canada > Saskatchewan (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.44)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract Water injection is often used as a recovery method for light oil reservoirs; however, for heavy oil reservoirs its efficiency is not so high mainly due to the unfavorable water-oil mobility ratio. For this reason, well placement is an important step of the production strategy definition because it can guarantee the economic viability of heavy-oil, deep water fields. This work aimed to analyze the behavior of heavy oil displacement by water injection, through both experimental and numerical simulation studies. A rectangular plate filled with porous media was used; its petrophysical characteristics were determined, as well as the relative permeability and capillary pressure. Two horizontal wells were used and the laboratory test was performed in two stages: first, an oil saturation phase and then a displacement phase. Water saturation maps were generated for the two stages, in order to better analyze distortions due to friction effects in the horizontal wells. A numerical simulation model was built to reproduce the behavior observed in the experiment and compare the friction pressure drop effects. It was further used as the basis of a hypothetical reservoir prototype, in field scale; the results from the simulations reproduced the experiment data qualitatively, however, some differences were observed. The friction pressure drop in the wellbore did not seem to affect the flow, especially according to the simulation results. Introduction With more frequent use of horizontal wells and new offshore oil discoveries of viscous oil, it is important to correctly describe the behaviour of viscous oil displacement in porous media[1]. This work aimed to study such behavior through a methodology that involved an experimental displacement test by injecting water in viscous oil through horizontal wells, and the characterization of a porous media. The fluids and porous media characterization[2] are presented in a correlated work[3]. Since this work involves very unfavourable mobility ratio, the initial discussion will focus on the conditions for displacement stability taking into consideration the high oil viscosity. Scale transformation from a model to a prototype was studied and the results for the prototype were calculated by scale transformation and by numerical simulation. The pressure, production and saturation distributions were simulated for the model and compared to the laboratory measurements. Porous Media. The porous media is an Eolian sandstone from Botucatu formation[4,5] obtained from an outcrop in Ribeirão Claro, PR, Brazil. It was preliminarily cut in a parallelepiped form (88cm × 33cm × 3.2cm), with 24% porosity and 587 mD absolute permeability[6]. The capillary pressure and the water oil stable relative permeabilities[7] can be seen in Table 1, where the normalised water saturation presented is defined by Eq. (1): (1) Oil Displacement Test Experimental and Simulation Model Results. The plate was saturated with water under vacuum. The initial water saturation was obtained by injecting the 212 cP viscous oil laterally in linear displacement geometry; the oil injection rate was 0.15 cm3/min. Figure 1 shows a picture[3] of the encapsulated rock plate used in the experiments and the laboratory apparatus. The operating pressure had to be kept to low values due to the large superficial area of the model, otherwise the plate containing the porous media could be damaged. This phase of the experiment provided the irreducible water saturation (Swi) for Eq. (1).
- North America (0.68)
- South America > Brazil (0.67)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.85)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract In order to help heavy oil upgraders and petroleum refineries optimize hydrotreater performance, a predictive hydrotreating process model is being developed to eventually predict the quality of the hydrotreated products under certain operating conditions. To establish this model, a number of important issues have been addressed and this paper summarizes the research results pertaining to these issues. 1. Introduction Current environmental regulations require production of ultra-low sulphur diesel (ULSD) in the near future. In the US and Canada sulphur content in on-road diesel has to be reduced from 500 ppm to 15 ppm by 2007 [1, 2]. In most European countries and some other developed countries, similar or even tougher regulations on sulphur content in diesel fuels will be implemented. Such stringent specifications create a serious challenge to refineries. Process modeling and simulation is essential to both new hydrotreater design and existing hydrotreater revamping/retrofitting. Predicting hydrotreater performance in ultra-low sulphur operation mode, with various feedstocks and process operating conditions, is one of the most important and difficult challenges refiners are facing [3,4]. A hydrotreating process model is currently being developed at the National Centre for Upgrading Technology (NCUT) to optimize hydrotreater performance, and in the longer term, to provide a predictive tool to facilitate hydrotreater design. This model, when completed, will not only predict the product yield, major reactants conversion, and hydrogen consumption, but also the product quality (such as density, viscosity, cetane number, and sulphur and nitrogen contents, etc.) of the individual fractions of the total hydrotreated liquid product, given a detailed characterization of the feedstock, unit configuration, and operating conditions. To achieve this goal, research work has been and is still being conducted in the following areas: 1) characterization, sulphur and nitrogen speciation of petroleum fractions; 2) product quality modeling; 3) detailed kinetics study of hydrodesulphurization (HDS); 4) molecular representation of petroleum feedstocks; and 5) vapor-liquid phase equilibrium under commercial hydroprocessing conditions and its effect on HDS. This paper summarizes the key research activities in the above-mentioned areas, and presents some typical experimental and computational results, focusing on HDS kinetics studies. 2. Characterization, Sulphur and Nitrogen Speciation of Petroleum Fractions Naturally, physical properties and product quality of petroleum fractions - such as density, viscosity, cetane number - are highly correlated to the fraction's chemical composition (hydrocarbon type distribution). In order to model and simulate HDS reaction kinetics in a hydrotreater operated under ULSD conditions, it is necessary to know the required peak-by-peak speciation of sulphur and nitrogen compounds. A number of characterization methods have been developed to provide information on by-boiling-point distributions of hydrocarbon types, and sulphur and nitrogen speciation in middle distillates. Brief descriptions of these methods follow. PIONA (Paraffin-Isoparaffin-Olefin-Naphthene-Aromatics): PIONA analysis provides compositional distribution of paraffins, isoparaffins, olefins, naphthenes and aromatics by carbon number (from 3 to 11) in the boiling range of IBP-200°C. GC-MS (Gas Chromatography-Mass Spectrometry): The oil sample is first separated into saturate, olefinic, aromatic, polar and ashphaltenic fractions by solid phase extraction (SPE) or open column chromatography (SARA). The saturate and the aromatic fractions are analyzed by GC-MS method and the olefin and polar fractions are quantified with GC-FID. In both analyses, the quantitative calculations are performed from 200°C to 540°C, giving by-boiling-point distribution of various hydrocarbon types in saturates, aromatics, polars, asphaltenes and olefins.
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Downstream (1.00)