Sanyal, Tirtharenu (Kuwait Oil Company) | Al-Hamad, Khairyah (KOC) | Jain, Anil Kumar (KOC) | Al-Haddad, Ali Abbas (KISR) | Kholosy, Sohib (KISR) | Ali, Mohammad A.J. (Kuwait Inst. Scientific Rsch.) | Abu Sennah, Heba Farag (Kuwait Oil Company)
Improved oil recovery for heavy oil reservoirs is becoming a new research study for Kuwaiti reservoirs. There are two mechanisms for improved oil recovery by thermal methods. The first method is to heat the oil to higher temperatures, and thereby, decrease its viscosity for improved mobility. The second mechanism is similar to water flooding, in which oil is displaced to the production wells. While more steam is needed for this method than for the cyclic method, it is typically more effective at recovering a larger portion of the oil.
Steam injection heats up the oil and reduce its viscosity for better mobility and higher sweep efficiency. During this process, the velocity of the moving oil increases with lower viscosity oil; and thus, the heated zone around the injection well will have high velocity. The increase of velocity in an unconsolidated formation is usually accompanied with sand movement in the reservoir creating a potential problem.
The objective of this study was to understand the effect of flowrate and viscosity on sand production in heavy oil reservoir that is subjected for thermal recovery process. The results would be useful for designing completion under steam injection where the viscosity of the oil is expected to change due to thermal operations.
A total of 21 representative core samples were selected from different wells in Kuwait. A reservoir condition core flooding system was used to flow oil into the core plugs and to examine sand production. Initially, the baseline liquid permeability was measured with low viscosity oil and low flowrate. Then, the flowrate was increased gradually and monitored to establish the value for sand movement for each plug sample. At the end of the test, the produced oil containing sand was filtered for sand content.
The result showed that sand production increased with higher viscosity oil and high flowrate. However, sand compaction at the injection face of the cores was more significant than sand production. In addition, high confining pressure contributes to additional sand production. The average critical velocity was estimated ranged from 18 to 257 ft/day for the 0.74 cp oil, 2 to 121 ft/day for the 16 cp oil, and 1 to 26 ft/day for the 684 cp oil.
Blunt, Martin Julian (Imperial College) | Al-Jadi, Manayer (Kuwait Oil Company) | Al-Qattan, Abrar (KOC) | Al-Kanderi, Jasem M. (Kuwait Oil Company) | Gharbi, Oussama (Imperial College) | Badamchizadeh, Amin (CMG) | Dashti, Hameeda Hussain (Kuwait Oil Company) | Chimmalgi, Vishvanath Shivappa (Kuwait Oil Company) | Bond, Deryck John (Kuwait Oil Company) | Skoreyko, Fraser A. (CMG)
The Magwa Marrat reservoir was discovered in the mid-1980s and has been produced to date under primary depletion. Reservoir pressure has declined and is approaching the asphaltene onset pressure (AOP). A water flood is being planned and a decision needs to be taken as to the appropriate reservoir operating pressure. In particular the merits of operating the reservoir at pressures above and below the AOP need to be assessed.
Some of the issues related to this decision relate to the effects of asphaltene deposition in the reservoir. Two effects have been evaluated. Firstly the effect of in-situ deposition of asphaltene on wettability and the influence that this may have on water-flood recovery has been investigated using pore scale network modes. Models were constructed and calibrated to available high pressure mercury capillary pressure data and to relative permeability data from reservoir condition core floods. The changes to relative permeability characteristics that would result from the reservoir becoming substantially more oil-wet have been evaluated. Based on this there seems to be a very limited scope for poorer water flood performance at pressures below AOP.
Secondly the scope for impaired well performance has been evaluated. This has been done using a field trial where a well was produced at pressures above and substantially below AOP and pressure transient data were used to estimate near wellbore damage "skin??. Also compositional simulation has been used to estimate near wellbore deposition effects. This has involved developing an equation of state model and identifying, using computer assisted history matching, a range of parameters that could be consistent with core flood experiments of asphaltene deposition. Results of simulation using these parameters are compared with field observation and used to predict the range of possible future well productivity decline.
Overall this work allows an evaluation of the preferred operating pressure, which can drop below the AOP, resulting in lower operating costs and higher final recovery without substantial impairment to either water-flood efficiency or well productivity.
Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field development plans. All field data acquisitions from seismic, well logging, production and geomechanical monitoring to enhanced oil recovery operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model in advance of the field development and associated design and operations is essential for a successful implementation of such projects. Furthermore, utilizing a more reliable model can in-turn provide the basis in the decision making process for control and remediation of formation damage.
One of the key identifier of the subsurface model is accurately predicting the hydraulic flow units. There are several models currently used in the prediction of these units based on the type of the data available. The predictions using these models are differing significantly due to the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions increasing the need for better models to enhance the predictions.
A new approach has been developed in this study for predicting the petrophysical properties improving the reservoir characterization. Poiseuille flow equation and Darcy equation were coupled taking into consideration the irreducible water saturation in the pore network. The porous media was introduced as a domain containing bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis were performed on 17 Berea sandstone samples and the petrophysical properties were measured and XRD analysis was conducted. In addition, core permeabilities were predicted using a new permeability model and the results were compared to the measured permeability data. In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers. Afterwards, by iteration and calibration of the laboratory data, the more realistic number of hydraulic flow units was
The same model was also implemented to a Cotton Valley tight gas reservoir in Northern Louisiana in order to determine the flow units. A comparative study shows that the new model provides a better distribution of hydraulic flow units and prediction of the petrophysical properties. Using the new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for both the Berea sandstone and Cotton Valley tight gas sand experimental data and the model predictions using the new permeability model show the wider range of applicability for various reservoir conditions.