Papers by Dr. Tawfiq Obeida
Proceedings of SPE Annual Technical Conference and Exhibition, Oct 1, 2005
All Days, Oct 28, 2007
Generating saturation functions (capillary pressure or J-functions), to initialize complex carbon... more Generating saturation functions (capillary pressure or J-functions), to initialize complex carbonate reservoir, always presents challenge to Petrophysicists and reservoir engineers, especially with no SCAL data available or any existing rock properties trends such as porosity-permeability relationship which are used to assign saturation function in 3D models. The proposed method requires initial water saturation (Swi) distribution in 3D model in hand (first stage) and then the Swi distribution recalculated more accurately (second stage) using group of capillary pressure (Pc) curves based on Swi intervals. Calculating Swi distribution in two stages should not impose any limitations since in the first stage Swi distribution can be estimated by many ways such as J-functions (4), group of Pc curves based on porosity intervals (part of this work). Otherwise, it may be estimated by any girding software which uses Swi log-data, but this method is not recommended since the software would give erroneous estimation of Swi in the areas of no well control such as in the transition zone area. The proposed method calculates the Swi distribution in two stages, first the Swi calculated by Pc curves based on porosity rages, then in the second stage the Swi recalculated using group of Pcs based on water saturation ranges. A script file was written to differentiate between these regions and assign saturation numbers (SATNUMs) for each saturation region which used in the simulator to initialize the dynamic model. Shuaiba reservoir is presented as study case here to demonstrate the capability of the proposed method. The proposed procedure can be to initialize huge complex carbonate reservoir such as Shuaiba formation in the United Arab Emirates. The initial water saturation profile from log data matched the water saturation calculated by the dynamic model in 90% of the wells (more than 100 wells at initial water saturation). The proposed procedure eliminates the tedious efforts to find rock property trends such as porosity-permeability correlations, which in many carbonate reservoirs may not exit, in order to assign a saturation function for each porosity/permeability range(s). The difference in initial oil in place (STOOIP) calculations between the static model (40 million cells) and the dynamic model (2.7 million cells) is less than 2 percent. It can be used also in many heterogeneous reservoirs to reduce the uncertainty in STOOIP and thus reserves estimations.
All Days, Oct 9, 2005
Calculation of initial fluid saturations is a critical step in any 3D reservoir modeling studies.... more Calculation of initial fluid saturations is a critical step in any 3D reservoir modeling studies. The initial water saturation (Swi) distribution will dictate the original oil in place (STOIP) estimation and will influence the subsequent steps in dynamic modeling (history match and predictions). Complex carbonate reservoirs always represent a quit a challenge to geologist and reservoir engineers to calculate the initial water saturation with limited or no SCAL data available. The proposed method in this study combines core data (permeability) from 32 cored wells with identifiable reservoir rock types (RRTs) and log data (porosity and Swi) to develop drainage log-derived capillary pressure (Pc) based on rock quality index (RQI) and then calculate J-function for each RRT which was used to calculate the initial water saturation in the reservoir. The initialization results of the dynamic model indicate good Swi profile match between the calculated Swi and the log-Swi for 70 wells across the field. The calculation of STOIP indicates a good agreement (within 3% difference) between the geological 3D model (31 million cells fine scale) and the upscaled dynamic model (1 million cells). The proposed method can be used in any heterogeneous media to calculate initial fluid saturations.
Elsevier eBooks, 1991
Abstract Experiments were conducted to elucidate the principal mechanism(s) of microbial enhanced... more Abstract Experiments were conducted to elucidate the principal mechanism(s) of microbial enhanced oil recovery at simulated subsurface reservoir conditions up to 1500 meters depth. Two species of bacteria were used: Bacillus licheniformis JF-2 and Clostridium acetoqutvlicum. Sandstone cores (70 cm 3 PV) were equilibrated to the desired simulated reservoir conditions, saturated with oil and brine, and flooded to residual oil saturation. The waterflood brine was displaced with a nutrient solution (3% cattle-feed-molasses in brine). The cores were then inoculated with bacteria (10° cells/ml) and shut-in. The pore pressure was monitored until there was no further increase in pore pressure. Finally, a pressure maintenance waterflood was conducted and the additional oil recovery was recorded (17–19%). Pore pressure increases up to 23 MPa (from an initial pressure of 17 MPa) due to biogenic gas was observed. The gas dissolved in the oil and brine establishing a solution gas drive mechanism. The MEOR recovery efficiency was directly related to the dissolved gas-oil ratio. The principal MEOR mechanism observed in this work was solution gas drive. All other possible mechanism (surface tension reduction, pH reduction, selective pore plugging, etc.) were shown to be minor compared to solution gas drive. The experiments suggested a procedure for field application of gas-generating bacteria.
Society of Core Analysis …, 2007
... 1/12 ACCEPTABLE WATER-OIL AND GAS-OIL RELATIVE PERMEABILITY MEASUREMENTS FOR USE IN RESERVOIR... more ... 1/12 ACCEPTABLE WATER-OIL AND GAS-OIL RELATIVE PERMEABILITY MEASUREMENTS FOR USE IN RESERVOIR SIMULATION MODELS Zubair Kalam, Tawfiq Obeida and Abdurrahman Al Masaabi Abu Dhabi Company for Onshore Oil Operations, Abu Dhabi (UAE) ...
Pilot objectives are usually predetermined before pilot field implementation. In order to study d... more Pilot objectives are usually predetermined before pilot field implementation. In order to study different pilot performance predictions, dynamic reservoir simulation is used as screening tool to ensure pilot designs meet pilot objectives. A Mechanistic "box " model is a limited size simulation model used to compare different pilot configuration performances on an equal basis and so saves both CPUs and simulation time. A 1 km x 1 km mechanistic model was constructed with refined grid of 25m x 25m. The reservoir properties, attributes and layering used are similar to the geological "static" model to avoid upscaling issues. Transmissibility multipliers were used at the boundaries of the mechanistic model and production or injection rates of the edge wells were constrained to mimic full pattern performance. Several pilot scenarios were studied in terms of well configurations, well spacing, well type (vertical or horizontal), well completion (reservoir sub-zone), injection/production rates, injected fluid (water, gas), injection continuity (continuous injection, WAG) and WAG cycles. All of these prediction cases were run under reservoir voidage replacement. Certain criteria were selected to screen these cases such as recovery factor at breakthrough, ultimate recovery factor, sweep efficiency, injection rates and breakthrough time. More than fifty cases were run and screened using mechanistic models. A number of these cases, those which meet the pilot objectives, were selected to be run using larger sector model for comparison with the mechanistic models. Results show good agreement between the mechanistic model and sector model results. The mechanistic model is a good tool to quickly screen many pilot scenarios rather than running much larger compositional models. The prediction results of the pilot performance can be used to create Tornado charts to determine the impact of key uncertainty parameters on oil recovery, sweep efficiency and breakthrough time. These charts will dictate the pilot design and pilot monitoring requirements. Introduction: To propose a new pilot in particular part of the field, first the pilot objectives should be clear from the beginning. Bases on the pilot objectives, a screening study were conducted to select most preventative area(s) in the field in terms of: 1-Subsurface geological parameters such as reservoir structure, faults, reservoir properties/heterogeneity (cored wells within the pilot area reduce the reservoir properties uncertainties) , reservoir fluid content, area closure and reservoir pressure. 2-Surface constraints such as flow lines, gathering stations to handle pilot production effluent contaminated with injected fluids. Injectant availability at the injection point and injection facilities
Laboratory studies have been performed to evaluate the impact of acid gas (80% H2S, 20% CO2) and ... more Laboratory studies have been performed to evaluate the impact of acid gas (80% H2S, 20% CO2) and CO2 injection on the carbonate matrix properties at reservoir conditions. Injectivity abnormalities have been reported in the literature in several WAG projects involving CO2 and loss of injectivity has been crucial factor in many of these projects. However, literature data shows that some reservoirs loose injectivity and others increase injectivity after the first CO2 slug is injected. Change in rock properties due to fluid/rock interaction can account for some of the injectivity loss. In this paper we will report on recent laboratory study that was conducted using limestone and dolomite reservoir core samples from a carbonate reservoir in Abu Dhabi. The laboratory program used core plugs, or plug composites, that had been aged with reservoir oil at a representative initial water saturation prior to the gas displacement. The displacements were performed with three fluids: 1) Vapor phase CO2 2) Acid gas (80% H2S, 20% CO2) 3) Brine saturated with CO2 The vapor phase CO2 and acid gas displacements were considered to be typical of those found near a gas injector, whereas the brine saturated with CO2 displacement was more representative of the reservoir away from the well bore or found during a WAG process. The displacements were conducted at a series of increasing rates. After 75 pore volumes the plug was left to soak for 48 hours in the displacing fluid. Two further displacements were then performed. Following the displacement tests, an assessment of damage to the core plug was made by measuring the porosity, permeability, SEM, XRD, MICP and taking thin sections of the core plug. This paper also presents laboratory work to study CO2 solubility in different brine salinities up to 250 K ppm at different reservoir temperatures up to 149 C and pressures up to 400 bar. A CO2 solubility model is proposed to calculate solubilities at representative salinity and previlent pressures and temperatures. The preliminary results show that in most of the experiments no significant change in permeability was observed. However, in some experiments both enhancement and decrease in permeability was reported. The results of this ongoing study will strongly impact the planning of EOR development options. Injection of CO2 or acid gas will be significantly hampered if the gas injection results in matrix plugging or core damage, and needs to be appropriately evaluated for the reservoir under consideration.
Fluid saturation distribution at initial reservoir conditions is vital for calculation of origina... more Fluid saturation distribution at initial reservoir conditions is vital for calculation of original oil in place (STOOIP) and reservoir simulation (dynamic models). It is a critical step in model initialization, since the subsequent step (quality of history matching) is largely dependent on the initial fluid distribution at time zero. In many reservoirs there are limited or no SCAL (drainage capillary pressure) data available and in many cases, the available limited SCAL data has poor quality and subjective plug selection. However, log-data (open hole logs, OHL) and routine core analysis (porosity and permeability measurements) are usually more available. The proposed method combines OHL and routine core analysis (RCA) to derive saturation functions for carbonate reservoirs with complex pore structure. The proposed method uses a multi-regression technique to relate water saturation to height above FWL and rock quality index (RQI) for each reservoir rock type (RRT). This method already been tested in carbonate reservoirs such as Shuaiba reservoir and Thamama-group formations. This study used 58 core wells penetrating Thamama reservoir with permeability measurements covering six petrophysical groups. The comparison results show a good match between the calculated initial water saturation (Swi) from the dynamic model. The STOOIP calculations indicated good agreement (within 3% difference) between the dynamic and static models
Modeling Hysteresis is an important task when simulating water alternating gas (WAG) scheme. Sinc... more Modeling Hysteresis is an important task when simulating water alternating gas (WAG) scheme. Since the displacement process in the reservoir changes from drainage (desaturation) to Imbibition (saturation) at different values of changing water saturation direction. Relative permeability and capillary pressure Hysteresis should reflect this process in reservoir dynamic models. Some dynamic models use only Imbibition relative permeability and capillary pressure for a given reservoir rock type. This would not allow the model to follow an "appropriate path" of saturation changes in the relative permeability and capillary pressure curves. Accounting for non wetting phase (oil) Hysteresis is more important than the wetting, since it controls oil mobility and thus recovery. This work consists of two parts: the first part consists of build a 1D model to evaluate the simulator Hysteresis model(s) by comparing the results obtained from simulator build-in Hysteresis with correlation driven "scanning" curves for relative permeability and capillary pressure. Also this model used to asses the impact of Hysteresis in a WAG case. The second part consists of constructing a 3D mechanistic model (1 Km x 1 Km) with full geological description to simulate a line-drive CO2 WAG pilot. Two WAG prediction cases were studied; one cases uses simulator build-in Hysteresis model and the other uses manual generated "scanning" curves. The pilot performance results such as oil production, recover factor, water cut, GOR and CPU time were used for comparisons. The results from both parts indicated comparable results between simulator build-in Hysteresis models and correlation models. The results from the first part indicated a significant change in recovery in the WAG case with Hysteresis in comparison with no Hysteresis case.
Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 20... more Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 36 November 2008. This paper was selected for presentation by an SPE program ...
Proceedings of SPE/EAGE Reservoir Characterization and Simulation Conference, 2007
North Africa Technical Conference and Exhibition, 2010
... of Gas Injection Pilot in Giant Carbonate Reservoir in the Middle East Tawfiq Obeida, Adrian ... more ... of Gas Injection Pilot in Giant Carbonate Reservoir in the Middle East Tawfiq Obeida, Adrian Gibson, Hussain Al-Hashemi (ADCO), Bikram ... Acknowledgment The authors would like to thankAbu Dhabi National Oil Company (ADNOC) and Abu Dhabi Company for Onshore Oil ...
EUROPEC/EAGE Conference and Exhibition, 2007
Teaching Documents by Dr. Tawfiq Obeida
SPE, 2015
Modeling Hysteresis is an important task when simulating water alternating gas (WAG) scheme. Sinc... more Modeling Hysteresis is an important task when simulating water alternating gas (WAG) scheme. Since the displacement process in the reservoir changes from drainage (desaturation) to Imbibition (saturation) at different values of changing water saturation direction. Relative permeability and capillary pressure Hysteresis should reflect this process in reservoir dynamic models. Some dynamic models use only Imbibition relative permeability and capillary pressure for a given reservoir rock type. This would not allow the model to follow an "appropriate path" of saturation changes in the relative permeability and capillary pressure curves. Accounting for non wetting phase (oil) Hysteresis is more important than the wetting, since it controls oil mobility and thus recovery. This work consists of two parts: the first part consists of build a 1D model to evaluate the simulator Hysteresis model(s) by comparing the results obtained from simulator build-in Hysteresis with correlation driven "scanning" curves for relative permeability and capillary pressure. Also this model used to asses the impact of Hysteresis in a WAG case. The second part consists of constructing a 3D mechanistic model (1 Km x 1 Km) with full geological description to simulate a line-drive CO2 WAG pilot. Two WAG prediction cases were studied; one cases uses simulator build-in Hysteresis model and the other uses manual generated "scanning" curves. The pilot performance results such as oil production, recover factor, water cut, GOR and CPU time were used for comparisons. The results from both parts indicated comparable results between simulator build-in Hysteresis models and correlation models. The results from the first part indicated a significant change in recovery in the WAG case with Hysteresis in comparison with no Hysteresis case.
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Papers by Dr. Tawfiq Obeida
Teaching Documents by Dr. Tawfiq Obeida