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Collaborating Authors
Institute of Petroleum Engineering, Heriot-Watt University
Modelling of Asphaltene Precipitation in Well Column of Iranian Crudes: Kuapl Case Study
Soulgani, B.S. (Sharif University of Technology) | Tohidi, B. (Institute of Petroleum Engineering, Heriot-Watt University) | Rashtchian, D. (Sharif University of Technology) | Jamialahmadi, M. (Petroleum University of Technology)
Abstract Asphaltene precipitation and deposition is a serious problem in many Iranian fields. The deposited asphaltene results in partial or total blockage of the wellbore, reducing or completely seizing oil production. This paper presents a new approach, based on PVT data, for thermodynamic modeling of asphaltene precipitation. The developed model has been combined with temperature and pressure modeling of the wellbore. The combined model has been used to predict the depth of asphaltene precipitation in the wellbore in several fields in an Iranian field (Kupal), as case study. The results are compared with the field data of asphaltene problems in various wells in Kupal field, as well as the measured depth of obstruction when applicable. There is a good agreement between the predictions and the field data. Finally, a sensitivity analysis has been conducted to simulate the effect of various operational parameters, including; flow rate, wellhead pressure and tubing diameter. The results provide important guidelines in minimizing the risks associated with asphaltene deposition. Introduction Asphaltenes are the heaviest fraction of crude oils which are polyaromatic structures or molecules, containing heteroatom (i.e. S, O, N) and metals (e.g. Va, Ni) that exist in petroleum fluids in an aggregated state. These aggregates are stabilized in solution by resins and aromatics, which act as peptize agents. Asphaltenes and resins, are in the thermodynamic equilibrium at static reservoir condition. However changes in thermodynamic condition such as pressure, temperature or compositions during oil production may cause stabilized asphaltenes precipitate out of fluid and could deposit in reservoir, wellbore, wellstring, transport pipeline or surface processing facilities. Since pressure and temperature changes extremely through production string, this area is the most susceptible for asphaltene precipitation. Deposition of asphaltene on the wall of production string reduces available diameter to oil flow, subsequently, oil production rate decreases. Gradually, oil flow path is plugged by increasing the thickness of deposited asphaltenes. In addition to economical damages as result of seizing oil production, the costs could increase for removing asphaltene obstruction plug by chemical or mechanical treatments. The mechanical treatment of asphaltene removal do not use practically. Because this process is time consuming and sometimes impractical owing to some parts of production system are not accessible. Therefore the most of asphaltene depositions are removed by chemical treatments. It is essential to know the depth of asphaltene deposition in order to implement a successful asphaltene removal operation. Because by knowing the depth of asphaltene deposition, the amount of chemical could be determined. Also, the risk of stuck reduces for coil tubing tool operation. Therefore, asphaltene removal treatment could be faster. The operational production condition affects on the asphaltene deposition in wellstring. Therefore, operational parameters should be known to prevent or eliminate the asphaltenes deposition damages in well string. Thus damages could be reduced by alerting operating conditions. This paper tries to find an approach that is capable to predict asphaltene deposition in well string and studies the effect of different factors on the process of asphaltene deposition including; flow rate, wellhead pressure and tubing diameter.
- North America (0.94)
- Asia > Middle East > Iran > Khuzestan (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Asia > Middle East > Iran > Khuzestan > Zagros Basin > Kupal Field (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Oued Mya Basin > Hassi Messaoud Field (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Berkine Basin (Trias/Ghadames Basin) > Hassi Messaoud Field (0.99)
The Influence Of Overflush Fluid Type On Scale Squeeze Life Time - Field Examples And Placement Simulation Evaluation
Jordan, M.M. (Nalco) | Mackay, E.J. (Institute of Petroleum Engineering, Heriot-Watt University ) | Vazquez, O. (Institute of Petroleum Engineering, Heriot-Watt University)
INTRODUCTION Scale Squeeze Process ABSTRACT This paper outlines how developments in the placement software are able to predict the squeeze lifetime when using different overflush fluid types (hydrocarbon overflush vs. seawater overflush). The study present field data from two production wells, each treated with the same aqueous scale inhibitor. The initial squeeze treatment for each well used a diesel overflush to displace the chemical (low water cut wells). Subsequent squeeze treatments to these wells utilised the same inhibitor but with seawater displacement. It is clear from field returns data that the seawater rather than marine diesel improved chemical placement and extended treatment life. The theory behind this phenomenon is be outlined along with the changes to the placement software that can now predict this effect, so allowing more accurate treatment designs to be generated. Scale inhibitor squeeze treatments for preventing carbonate and sulphate scales are well-established procedure in onshore and offshore oil production facilities. In general, the squeeze process, illustrated in Figure 1, comprises pumping a preflush solution (0.1% v/v inhibitor in KCl or injection quality seawater), followed by the selected scale inhibitor (normally in the concentration range of 5% to 20% v/v in KCl or injection quality seawater), and finally an overflush stage (using inhibited seawater or KCl). The well then remains shut-in for a period (6-24 hours) allowing the inhibitor chemical to react with and be retained by the reservoir rock, before the well is flowed back into the test separator and the main process vessels. . The function of each stage is described below. Preflush and Spacer Stages This stage is, in its simplest form, designed to displace the tubing and production interval fluids back into the formation. This creates a buffer zone between the formation fluids and the treatment chemicals. This is often desirable due to chemical and produced fluid (oil, brine) compatibility concerns. The preflush stage also reduces the tubing and near wellbore temperature, which reduces the scale inhibitor adsorption rate and reduces the risk of premature precipitation of a treatment designed to phase separate at elevated temperatures. The preflush stage may contain a small concentration (<0.5% v/v) of scale inhibitor along with a small concentration of surfactant or demulsifier to reduce emulsion risk as the produced fluids are displaced back into the formation. In more complex treatment programs mutual solvents are applied at higher concentration (10-100% v/v). These chemicals perform two functions; they clean oil films from the mineral surfaces, increasing the surface area for chemical adsorption, and during reflow, the chemicals can remove much of the residual water saturation left in the near wellbore region following an aqueous scale squeeze treatment. The result of such preflush treatments is longer squeeze lifetime and faster well clean up rates. A spacer stage may also be present in squeeze programs between the preflush and the main treatment. Such stages are normally included when the preflush itself can react with the main treatment stage.
- Europe > United Kingdom (0.94)
- North America > United States > Texas (0.69)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
- South America > Brazil > Campos Basin (0.99)
- North America > United States > Texas > East Texas Salt Basin > Alba Field (0.99)
- North America > United States > Mississippi > Improve Field (0.99)
- (4 more...)
Recovery Performance of Steam-Alternating-Solvent (SAS) Process in Fractured Reservoirs
Bagci, A. Suat (Institute of Petroleum Engineering, Heriot-Watt University) | Samuel, O.M. (Institute of Petroleum Engineering, Heriot-Watt University) | Mackay, E. (Institute of Petroleum Engineering, Heriot-Watt University)
Abstract Steam-Alternating-Solvent (SAS) process is a new promising recovery process for the production of heavy oils and bitumen resources. The process is used the advantages of the SAGD and VAPEX processes. This study presents a numerical simulation study of SAS process in fractured reservoirs which involves injecting steam and solvent alternately, and the basic SAGD well configurations. This simulation study investigated the effect of steam and alternately solvent injection into the prototype reservoir model under various reservoir and operating conditions on oil recovery. Dual and single porosity and permeability systems for both SAS and SAGD processes were also investigated. The injection schedule for alternating steam and solvent injection by running various sensitivities on fracture orientations, injection schedule, and pressure differential between injector and producer wells was studied to investigate the performance of SAS and SAGD processes in heavy oil reservoirs. Oil production rate for SAS process was higher than that of the SAGD process. The pumping schedules for the SAS process showed that the high production was achieved by injecting steam for a year and solvent for half the time. Higher injector-producer well pressure differential showed better productivity compared to a low pressure differential between injector and producer wells. Introduction Heavy oil deposits have being continually developed using a range of thermal and non thermal recovery processes. For this type of oil with high viscosities, the location of the oil is known within the reservoir and all that is needed is an efficient and economic way to recover the oil. To recover this heavy oil, it has to be made mobile by increasing its temperature to reduce its viscosity and also by injecting a solvent, a light hydrocarbon component to reduce the interfacial tension of the oil and hence upgrade it to less viscous oil. These viscosity reduction methods aided by horizontal well technology enable high oil recovery from heavy oil fields. Two processes used for the recovery of heavy oil are the: Steam Assisted Gravity Drainage SAGD and the vapour extraction process VAPEX [1, 2]. The SAGD process uses a dual well pair with an injector above and parallel to a producer. Steam is injected into the reservoir via the injector and a rising steam chamber that also spreads is formed and the steam heats up the heavy oil. The heated oil and condensed steam both flow under gravity to the producer below the injector. This process is in wide use and has a high oil recovery rate though at the expense of energy usage and hence, CO2 emissions. The VAPEX process uses a similar well configuration to that of the SAGD but has vaporized hydrocarbon injected into the reservoir which forms a solvent chamber. At the solvent chamber boundary, molecular diffusion of the solvent into the oil takes place and this reduces the oil's viscosity while increasing its mobility [3]. The solvent chamber grows and at the end of the solvent injection process, the reservoir is blown down and some solvent recovered, more solvent can be recovered if the oil is stripped of the injected solvent.
- North America > United States > Oklahoma (0.28)
- North America > United States > California (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
In-Situ Monitoring The Inhibiting Effect Of Detpmp On Caco3 Scale Formation By Synchrotronx-Ray Diffraction
Chen, Tao (School of Mechanical Engineering, University of Leeds) | Neville, Anne (School of Mechanical Engineering, University of Leeds) | Sorbie, Ken (Institute of Petroleum Engineering, Heriot-Watt University) | Zhong, Zhong (Brookhaven National Laboratory)
ABSTRACT The formation of calcium carbonate mineral scale is a persistent and expensive problem in oil and gas production. The aim of this paper is to further the understanding of scale formation and inhibition by insitu probing of crystal growth by synchrotron radiation Wide Angle X-Ray Scattering (WAXS) in the absence and presence of DiEthyleneTriaminePenta (MethylenePhosphonic acid) (DETPMP) scale inhibitor at elevated temperature. It has been shown that the nucleation and growth of various calcareous polymorphs and their individual crystal planes can be followed in real time and from this the following conclusions are reached. Two stages of scale formation have been identified: e and e stages. DETPMP significantly increases the induction time obviously at 10 ppm. DETPMP suppresses calcite formation and favours vaterite formation. DETPMP causes the change of lattice parameters of calcite crystals.
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.35)
Seismic Monitoring of Pressure Depletion Evaluated Using Azimuthal AVO Data?
Al Kindi, Faisal (Institute of Petroleum Engineering, Heriot-Watt University) | MacBeth, Colin (Institute of Petroleum Engineering, Heriot-Watt University) | Shams, Asghar (Institute of Petroleum Engineering, Heriot-Watt University)
ABSTRACT Azimuthal is investigated as a possible tool for time-lapse monitoring of pressure depletion in reservoirs for which fluid replacement or the signature due to fluid movement is negligible. A feasibility study is carried out for both onshore and offshore acquisitions, which have non-repeatable geometries between the baseline and monitor surveys. Modeling, followed by anisotropy estimation reveals that lack of repeatability between the different survey vintages as a significant challenge, particularly in the presence of background noise. The condition of a repeatable geometry is more critical than for the stacked response. For the geometry data used in this study, anisotropy estimates rapidly become unstable when pre-stack noise levels exceed 3 to 5 percent. Pressure drops in the reservoir must exceed 15 MPa in maximum fold areas for the OBC survey, and 7 MPa onshore, to permit detection of the corresponding anisotropy changes. The study suggests constraint using production data is necessary for more accurate resolution of pressure changes.
- North America > United States (0.72)
- Europe > United Kingdom (0.48)
- North America > United States > Colorado > Piceance Basin > Rulison Field > Mesaverde Formation (0.99)
- Europe > United Kingdom > North Sea > Southern Gas Basin (0.99)
Towards Accurate Quantitative Monitoring of Compacting Reservoirs Using Time-lapse Seismic
Corzo, Margarita (Institute of Petroleum Engineering, Heriot-Watt University) | MacBeth, Colin (Institute of Petroleum Engineering, Heriot-Watt University)
ABSTRACT The accuracy of estimating reservoir pressure using seismic amplitudes is studied using simulator to seismic modelling. To capture the physics of the reservoir process, the simulation involves coupled geomechanics and flow. Properties from a compacting chalk reservoir are used to guide the analysis. The study provides evidence that the amplitude-pressure relationship is strongly influenced by thickness variation, structure and overburden strain changes, and these must be adequately understood before accurate pressure estimates can be made.
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Hod Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/11 > Valhall Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/11 > Valhall Field > Hod Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)