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Abstract The trend for SAGD in Canada is towards low pressure steam injection. The primary reasons for this trend are both economical and operational in that low pressure translates to lower operating costs and improved recoveries.[1]Low pressure SAGD also requires an artificial lift system (ALS) in order to achieve desired production rates. This paper will discuss a unique ALS that was specifically developed for the lifting challenges associated with low pressure SAGD - the Hydraulic Gas Pump (HGP). This rodless technology utilizes high pressure gas to positively displace production fluid. At the time of the writing of this abstract, the HGP had passed rigorous lab testing and surpassed all performance expectations in a test well. Furthermore, it is currently being field-tested in a SAGD well in Canada. The paper concludes with the actual HGP field-test performance results from that well. Introduction From an ALS perspective, the well parameters from low pressure SAGD are extreme. Most systems that exist today cannot be successfully applied in this rigorous environment. Some of the typical well parameters and required lift performance characteristics are as follows:200 ยบC+ temperature capability: This is the expected bottom hole temperature that an ALS will experience. The challenge is that most forms of ALS have reciprocating or rotary moving parts that require dynamic seals. The elastomeric sealing materials that are commonly used are compromised at such elevated temperatures. [2] Variable capacity from approximately 1,000m3/d - 100 m3/d over the lifetime of the well: To provide one ALS from cradle to grave[3] requires a high volume system that has a turn-down ratio of 10:1. Existing systems cannot satisfy this requirement. Ability to handle multi-phase inflow: The attainment of optimal reservoir performance requires a down hole pumping system that operates at low intake pressures and low sub-cool values. The challenge is for the pumping system to be able to effectively handle oil, hot water and steam. Hot water flashing to steam is of particular concern as it can detract from pump efficiency, reduce the cooling effect that some down hole pumping systems require, and gas lock other systems. Low fluid shear and pressure drop: These are desirous in order to reduce the likelihood of tight emulsion and steam flashing. The challenge is that in order to operate effectively, a down hole pumping system must not have a torturous path or constrained inflow that would otherwise cause a pressure drop sufficient to flash hot water to steam. Intake pressures as low as 300 kPa: Some down hole pumping systems require significantly more pump intake pressure to work effectively. Ability to handle a wide range of fluid viscosity (1 - 2000 cps): Changes in viscosity can occur during start up, or due to oil/water emulsion. A down hole pumping system that is unaffected by viscosity change is therefore required. Solids handling capability: Although best efforts in sand control completion design are commonplace, a down hole pumping system should still be able to handle abrasives. Simplistic completion (no packer requirement). Low CAPEX and OPEX: A down hole pumping solution has to be cost effective.[3]
- North America > Canada (0.70)
- North America > United States (0.69)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems (1.00)
Abstract SINCOR is one of the major operators of the Orinoco Belt in Venezuela (Figure 1). It produces 8.5ยฐAPI 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 ยฐAPI 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 Jet pumping driven by light oil is one of the preferred lift methods for producing heavy oil in a deep heavy oil reservoir. Generally, the amount of light oil is too large to be accepted. One solution of reducing the amount of light oil is that partial produced fluid can be combined with the light oil at any reasonable ratio and then the produced fluid-light oil mixture is reinjected into the well as the power fluid. In this case, viscosity of the mixture keeps increasing and eventually reaches its equilibrium value, which is found to be a function of the reservoir oil viscosity, the light oil viscosity (VLO), the ratio of light oil (RLO) in the mixture (volumetric percentage) and the ratio of the well rate to the diluent rate (M ratio). Thus the optimal ratio of light oil in the mixture can be determined by using an iterative algorithm. All of the above-mentioned parameters result in a change of the viscosity of the produced fluid-light oil mixture and the pressure loss in the production string, especially the VLO and the RLO. A field application example shows that the amount of the light oil used can be reduced by more than 50%. Introduction It is difficult to produce heavy oil from wells deeper than 3000 meters by using the common artificial lift methods[1]. In this case, the sucker rod pump method undergoes rod stretch and breakage, while the submersible pump method suffers from high temperature and thrust bearing loads at high discharge pressure, furthermore, pump efficiency is significantly reduced at a low production rate. There should be sufficient gas source available for the gas lift method, although it is expensive for compressing the gas to a high pressure and difficult to achieve a low submergence. Therefore, more efficient methods need to be sought for producing oil from deep heavy oil reservoirs. Jet pumping method has been proposed as an efficient artificial lifting technique for heavy oil production[2โ7]. For this technique, in principle, a low pressure fluid in the reservoir is boosted and produced by mixing it with a high pressure fluid pumped downhole from the surface (Figure 1). Furthermore, the jet pumping method shows its advantages in producing oil in deep wells because of its simplicity, lack of moving parts, small size and ability to pump fluids with high viscosity or strong corrosivity. In addition, light oil can be used as power fluid in deep heavy oil wells due to the reduction of produced fluids viscosity and the reduction of the pressure loss in the production string. Reduction of the pressure loss is mainly ascribed to the instantaneous and better mixing of the power fluid and the reservoir fluid in the jet pump throat[8].A jet pump is a dynamic pump with a performance curve similar to that of a centrifugal pump, as shown in Figure 2[9]. While the light oil is used as the power fluid, the amount of the light oil should not only be enough to reduce the viscosity of the reservoir fluid in the production string, but also provide sufficient energy for the reservoir fluid to be lifted up to the surface. To maximize the lifting flexibility and the efficiency, it is advisable to operate the pump with high R ratio (nozzle area/throat area), which can provide high N ratio ((PD-PS)/(PN-PD)) in deep heavy oil wells, where PD, PS and PN are pump discharge pressure, pump section pressure and power fluid pressure (all pressures referred at pump depth)[10]. High efficiency can be obtained for low M ratios, which are proved to be suitable in the range of 0.3~1.2 in our study (Reservoir depth>4500m). In this case, as the power fluid (M=0.3~1.2), the mount of light oil should be 0.83~3.33 times of the well rate. While for viscosity reduction, the amount of light oil needs to be around 0.43 times of the well rate[11โ12]. Application of the jet pumping method is limited if a large amount of light oil is needed and the supply of light oil is insufficient. In order to reduce the amount of the light oil, a new technique is proposed in this paper whereby a portion of the produced fluid can be combined with the light oil at a reasonable ratio and then the produced fluid-light oil mixture can be reinjected into oil wells as the power fluid. The key issue of this new technique is how to determine the optimal ratio of light oil that would minimize the amount of light oil required, while guaranteeing the low viscosity of the fluid in the production string and reasonable well head power fluid pressure which should be provided by the surface facilities.
- North America > United States (0.46)
- North America > Canada > Alberta (0.28)
Abstract The accurate measurement of Oil, Water and Gas/Steam in heavy oil thermal production (SAGD and other Steam Flood Processes) is a very difficult task faced by the heavy oil industry. The accuracy of these measurements is critical for reservoir management and production diagnostics. Mulitphase flow meter technology has been used successfully around the world for over 10 years and in heavy oil "cold" production in Venezuela and other countries. But multiphase technology has never been used in Extra Heavy Oil Thermal Production. The Canadian heavy oil thermal producers regularly see production temperatures exceeding 200 C (392 F) and some wells are approaching 232 C (450 F). New technology is required to accurately measure wells producing at these elevated temperatures. The first field tests using a multiphase flow meter in a heavy oil thermal project was conducted by one of the major Canadian producers in the fall of 2004. Additional tests were completed during the summer of 2005 with another heavy oil producer. This paper will review the unique problems encountered with testing heavy oil in high temperature applications. The test results from multiple well tests and the accuracy of the multiphase flow meters when compared to the field reference will be presented. Introduction An estimated six trillion barrels of heavy oil and bitumen is available worldwide. A majority of these reserves are located in United States, Canada and Venezuela (1). Thermal-based recovery methods have been used since 1950's to recover oil from these reservoirs. Significant changes related to reservoir management and production facilities have been made (2). In the past decade new thermal recovery techniques such as the steam assisted gravity drainage (SAGD), two cyclic steam stimulation (CSS), steam and gas push (SAP) and vapor extraction (Vapex) processes have been developed and used to enhance the recovery of very heavy oil (1,3,4). Among these processes, the steam assisted gravity drainage has emerged as an effective technology for recovering oil from sand deposits that are too deep to be recoverable by surface mining(3,4). In the SAGD process, steam is injected continuously down one well while the mobilized bitumen and condensate steam are produced continuously up a second well. The injector and producer are drilled approximately 5 m apart. In some developments, horizontal wells are used to enhance reservoir access and well productivity (4). In the injector well, steam injection creates a chamber that grows as the steam condenses on the chamber walls and releases heat. Heated bitumen and condensed steam drain by gravity into the lower producing well and are pumped out. The oil-in-water emulsion produced by the SAGD process is very stable and requires chemical treatment and processing to separate the oil and water (5). Conventional gravity based test separators used in measuring well rates are not able to deal with this stable emulsion, in the presence of steam condensate and produced gas, as well as the high temperatures. Reference 5 has reported on a SAGD plant that processes a reverse emulsion of about 360 m3/day of oil and 1200 m3/day of water at 195โ200 C and 1800 kPa (260 psig). At the operating temperature of the separator (about 200 C) the produced water is less dense than bitumen. Wet oil exits from the bottom of the high temperature separator and enters a flash treater operated at temperatures above 145 C to flash out the steam. These conditions make it difficult for conventional gravity-based test separators, with limited retention time, to produce accurate measurements of the produced fluids.
- North America > United States > Texas (0.47)
- North America > United States > Colorado (0.28)
- North America > United States > California (0.28)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
Abstract The three-phase water-assisted flow of heavy crude oil with free gas (air) in a vertical glass pipe, at near atmospheric pressure and temperature conditions, is investigated, for possible applications to the articial lift of heavy oil. Water is injected so as to avoid oil-wall contact and reduce friction. The oil phase was a w/o emulsion with a viscosity of 5,040 mPa.s and a density of 971 kg/m3. For each combination of oil-water-gas flow rates, the flow pattern was determined using a high speed camera and the pressure gradient was measured with a differential pressure transducer. The results are presented in the form of flow maps based on superficial velocities and total pressure gradient plots, allowing comparisons with well known correlations. The main conclusion indicates the great viability of the water-assisted flow technique. Significant amounts of heavy oil have been discovered in offshore Brazil. Introduction Heavy oils are often defined as those having densities greater than 934 kg/m3 (<20 oAPI) and viscosities in the range 100โ10,000 mPa.s at reservoir conditions of pressure and temperature [1]. They represent a significant part of the Brazilian oil reserves, which, according to the National Petroleum Agency (2002), are approximately 3.2 billion oil barrels and mostly located offshore. The exploitation of these reserves, with the usual recovery and artificial lift technologies tends to be economically unattractive or unfeasible, which is partly due to the lower market value of heavy oils. However, with the progressive decline of light oil production, the importance and, consequently, the price of these fossil energy sources will tend to increase. The use of long horizontal length wells has been proposed to achieve high productivities but the injection of water in the reservoir tends to be not efficient, due to the unfavorable mobility difference between water and heavy oil [2]. Furthermore, in offshore deepwater fields, flow assurance problems such as hydrate, asphaltene and paraffin deposition risks indicate the need for improved thermal insulation and/or heat addition to the production line. However, water is readily available and its injection in liquid form requires low energy consumption. The artificial lift method for heavy oils is also critical especially in offshore deepwater applications since the conventional PCP technology does not provide high enough flow rates and ESPs require high power to overcome increased frictional flow losses of heavy oil or w/o emulsions. Refinery requirements include removal of nearly all the water present in the emulsion. This paper focuses the vertical upward three-phase pipe flow of heavy oil, air and water at several different combinations, in which water is injected to work as the continuous phase (water-assisted flow). A laboratory scale apparatus was built allowing flow pattern visualization and pressure drop measurement. Results are compared with some well-known oil and gas correlations and may be useful in either case when water is injected in the reservoir and forms a continuous phase in the production pipeline (BSW > 50 %), or when it is injected at pump exit, as in the oil-water "core flow" method [3โ5]. No previous work on vertical three-phase oil-water-gas flow has been found. Experimental Setup and Procedure The experiments were conducted in the setup shown in Figure 1, at the School of Mechanical Engineering of the State University of Campinas. The apparatus consisted of a separator tank, individual lines and pumping systems for water, oil and air, which joined at an injector nozzle, followed by a 2.84 cm i.d., 2.5 m long vertical glass tubing for the three-phase flow. The oil flow rate was measured with a Coriolis mass flow meter, whereas the water and air flow rates were read in rotameters. Pressure data in the test section were measured with differential and absolute pressure transducers connected to a data acquisition system.
- South America > Brazil (0.35)
- North America > United States (0.28)
- North America > Canada (0.28)
Abstract 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. Introduction The field of interest was areally very large and vertically geologicallycomplex, with multiple stacked reservoirs. Rock and fluid propertiesvaried significantly with reservoir, depth, and areal location. The crudewas very heavy, and an expensive processing facility was required for transportand marketing. The oil in place was large enough that the reserves werelimited primarily by the capacity of the processing facility (Fig. 1) and theduration of the production agreement (assuming a sufficient number of economicwells could be drilled to fill the facility). Early in the field life, there was the possibility of expanding theoperation by building a second facility. One of the critical decisions wasthe size of the second facility. Because it was early in the life of thefield, there was little production history and the field was not fullydelineated. Therefore, there remained significant uncertainty in reservoirperformance and thus in the number of wells required to fill a secondfacility. The situation certainly called for D&RA, but the decision tree wascomplex, comprising over 100 branches. The traditional solution would havebeen to run multiple full-field simulation cases to attempt optimization ofeach branch of the decision tree. However, that approach would have beennearly impossible to complete, because each simulation took a day to run (evenusing parallel processing and a dozen cpu's) and optimization would have been atrial-and-error process.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract This paper gives details concerning one of the newest producing fields in the North Sea, West of Shetland development. Examples of the pre-start up design and implementation challenges are dwelt on, as well as the philosophy taken when commissioning the plant and chemical injection facilities. The majority of the paper focuses on the first 6 months of production history and the way in which the management of production techniques was performed and in particular how actual operations differed to the planned and designed specifications. With production of a 20ยฐ API crude, significant operational challenges have been encountered with initial start up being a staged and controlled process. Details are given to the suite of production chemicals required to give complete flow assurance as well as to maintain plant integrity. The onset of water production brings with it a whole suite of different challenges with by far the most difficult being demulsification and this has been given particular attention. CLAIR FIELD BACKGROUND The Clair Field is located 75 km (40 miles) west of the Shetland Islands and is currently produced from a single fixed platform in 140 m of water (Figure 1). The field produces both oil (exported down a dedicated pipeline to Sullom Voe Terminal (SVT), Shetland) and gas (ties into the existing West of Shetland Pipeline, to SVT) with a GOR of 550 scf/bbl. The Clair reservoir extends over an area some 40 km by 20 km in complex Devonian and Carboniferous units covering 5 licence blocks (206/7a; 206/12; 206/8; 206/13a and 206/9). Current estimates of the likely oil are in excess of 4 billion barrels STOIIP, making Clair the largest undeveloped hydrocarbon accumulation in the UK Continental Shelf and a key component of future UK production strategy. The Clair Field was originally discovered in 1977 but a poor understanding of the reservoir properties (significant faulting and fracturing) combined with a competitive exploration and appraisal programme through the 1980s by the original four licence groups prevented a commercial development. In the early 1990s acquisition of 3D seismic data over the whole field occurred, and two wells were drilled in 1991 and 1992. Although they demonstrated commercial flow rates, the wells were not produced for long enough to give confidence in long term reservoir performance. In 1996, an extended performance test was conducted on well 206/8โ10z in the core area. Flowing at an average rate of 10 MDB for 23 days, with a peak of 18.5 MBD, the well performance changed the perception of the Clair reservoir by demonstrating sustainable crude oil delivery. The extent of the Clair field demands that it be produced as a phased development. The first phase builds on the successful 1996 well test and targets development of the Core, Graben and Horst areas (Figures 1 and 2). The reservoir is divided into nine fault-bounded segments having a common free water level and maximum oil column of 600 m. A gas cap is present in the structurally elevated ridge segments. The reservoir depth is 1,850 m TVDss and the initial reservoir pressure was 192 Barg with a temperature of 66.1ยฐC. Work is continuing to define this first development and has already begun with Clair Phase 2. The challenge for Clair is in understanding the issues of reservoir deliverability, well productivity and managing the cost base whilst adhering to the aspirations for a sustainable development. Clair will be the third West of Shetland development after Foinaven and Schiehallion.
- North America > Canada > Alberta (1.00)
- Europe > United Kingdom > Atlantic Margin (1.00)
- Europe > United Kingdom > Scotland > Shetland (0.24)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/9 > Clair Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/8 > Clair Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/7 > Clair Field (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (0.97)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (0.89)
Abstract Heavy oil represents a large quantity of hydrocarbon resources. Unfortunately its high viscosity makes it difficult to produce and to transport. Different solutions have been developed to transport heavy oil in pipeline like blending the crude oil by a light hydrocarbon. In this study we investigate a technique based on two-phase flow: pipeline lubrication. A thin water film is injected around the internal oil core and lead to the core-annular flow regime. Water lubricates the heavy oil and longitudinal pressure gradient is then largely reduced. An experimental study has been carried out where the influence of the water content and oil flow rate has been optimized for real heavy oil as the core of the flow. The tests were conducted in steady laminar flow at moderate flow rates. The results, obtained with annular water injection at the pipe wall, show a pressure drop reduction over than 90% as compared with the same product without lubrication. These results confirm the effectiveness of the lubricating process for heavy oil transport. Restart problems and specifically the limitation of restart pressure has been also investigated. Introduction Oil flow as a single phase in a pipeline is a spread out way of transporting hydrocarbon resources for very long distances. The relatively low viscosity of usual crude oil is a key issue for such a way of transport because of small flowing resistance. For higher viscosity, the pipe diameter can be increased and eventually mean flow velocity decreased, but for very high viscosity, large pipe and small velocity lead to a not economical transport technique. Multiphase flow is also now widely used because it brings the advantage to mix gas, water and oil, all together in a single pipe. However flowing conditions are more difficult to predict because the phase configurations are various. Core annular flow is one particular two-phase flow regime where the oil phase is in the center of the pipe and water is flowing near the wall surface. A very pleasant characteristic of this flow is that it is stable for an acceptable range of velocities and the pressure drop is very weak and does depend only softly on the oil viscosity. Moreover, it is well suited for heavy oils. Indeed, in this case, densities are close to the water one so that stratification is limited. Moreover, high viscosities slow down the core deformation and limit any modification of the flow regime. These remarkable properties of CAF have been observed for long time and industrial interest was noticed a hundred years ago! A 1904 patent of Isaacs and Speed [1] in the US mentioned first the ability to transport viscous products through "water lubrication". Despite this early concern, large-scale industrial pipelines for heavy oil are scarce and the first one was built only in the 70's. This Shell line near Bakersfield in California was 38 km long for a tube diameter of 15 cm. For more than ten years, a viscous crude oil has been produced in water lubricated regime. Since then, several studies were dedicated to Core Annular Flow regime, and different reviews of the published work have been written ([2]and[3]). It has been shown experimentally and theoretically that this particular flow regime is stable for a specific range of velocity [4] and produce very weak pressure drop. Below a certain velocity limit, the capillary instability breaks the inner core into slugs, and at rest, stratification occurs in the system.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.68)
Abstract Multiphase metering flow meters (MPFM) are being accepted more and more in oil and gas developments, replacing test separators, particularly on fields with large well networks. This is the case with Steam Assisted Gravity Drainage (SAGD) oil sands developments requiring large capital investment that need accurate production and reservoir data and have difficult processing techniques. This data includes:Real time measurement: good reservoir and steam chamber monitoring and steam injection versus oil production surveys. Cost reduction: steam oil ratio (SOR) optimisation, due to the economic and environmental cost of steam. Asset integrity: mitigation of the risk of steam breakthrough in oil producer wells. The flow meters have to be sized for either viscous liquids (water in oil emulsions) or less viscous, but very hot liquids (oil in water emulsions) and to differentiate between gas and steam, or be able to meter the gas and assess the steam loading. In SAGD developments the water content determination is essential and the meters have to include qualified systems for both high temperature and high water cut measurements. This paper outlines the business needs for MPFMs in SAGD and discusses the current difficulties with qualification, test loops, field trials and eventually, the perceived operational issues. The challenges facing multiphase metering in SAGD developments are as difficult as the industry faced when applying classical multiphase metering techniques several years ago. In order that these challenges are overcome it will be necessary for vendors and operators to develop and test the new technologies jointly. This will require that vendors dedicate sufficient effort in MPFM R&D and that operators participate in these developments, in JIP's and host field trials. Introduction Reservoir monitoring and modelling improves reservoir knowledge, simulation, reservoir optimisation, prediction of breakthrough times & well performance for different operating scenarios. Reservoir models and predictions are based in part on surface metering data. The reliability and uncertainty of this data defines the sensitivity of any reservoir model. Reservoir monitoring enables competent operating strategies to be set and is used to compile the year end reserves. Monitoring of well performance and production can provide continuous information on well behaviour throughout the well life. SAGD production will require:Initial steam injection rate (circulating - i.e. steam chamber creation and oil heating) Ramp up (with gas lift injection), Steam lift Gas lift\ Blow down, Break through Good reservoir monitoring can optimise the well spacing, and well length and contribute to the system learning curve for future developments. In addition to reservoir management, metering must be compliant with the required regulatory reporting needs.
Abstract A modified mechanistic model is formulated to predict the pressure drop in horizontal slug flow for two-phase flow (viscous liquid and air). The model is evaluated by using accurate PDVSA INTEVEP experimental data for liquid with viscosity of 480 cP. A comparison between the modified model and experimental data shows that the absolute average relative error in pressure drop prediction is less than 6%. Introduction Venezuela has the world largest heavy oil reserves. PDVSA has launched several projects to develop the technology for optimum exploitation and production schemes. Special attention have been focused on multiphase flow along the production system, which includes horizontal & multilateral wells, vertical wells (tubing & annular flow), pipelines and production networks. Multiphase flow is characterized for the existence of flow patterns. There are different types of them, where the most common one is called slug flow, see Fig 1. Therefore, proper production system design requires of reliable pressure drop models for slug flow. Current pressure drop models for slug flow, have been developed and validated for low viscosity oils. Fluid properties affect the slug flow characteristics as well as the behavior of the pressure losses. Available pressure drop models estimate the pressure gradient with average errors about 30% as can be seen in Fig 2. This uncertainty might affect CAPEX and OPEX up to 10%. The interest of this work is to develop a rigorous pressure drop model that can be applied for both light and heavy oils. The model should be validated initially with lab data and then with field data. Due to the lack of high quality laboratory data for pressure drop in heavy oils, PDVSA INTEVEP built a multiphase production laboratory. The experimental facility and the slug flow model will be described next. Experimental Setup Test facility description Experiments were carried out in a 2-in test loop facility at PDVSA INTEVEP. Lube oil (480 cP) and air were testing fluids.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Pipeline transient behavior (1.00)