Jabbar, MuhammadYousuf (ADNOC Offshore) | Xiao, Rong (ExxonMobil Production Company) | Teletzke, Gary F. (ExxonMobil Upstream Research Company) | Willingham, Thomas (ADNOC Offshore) | Al Obeidli, Amna (ADNOC Offshore) | Al Sowaidi, Alunood (ADNOC Offshore) | Britton, Chris (Ultimate EOR services) | Delshad, Mojdeh (Ultimate EOR services) | Li, Zhitao (Ultimate EOR services)
A laboratory study was performed to identify a robust chemical EOR solution for a complex low-permeability carbonate reservoir. The study consisted of two phases of work. The first phase included development of a surfactant-based EOR method (
This paper is focused on the polymer EOR evaluation and discusses the extensive evaluation process that was followed. The laboratory study included polymer rheology, thermal stability, and transport tests with a novel pre-shearing method, live-condition core flood tests to evaluate dynamic polymer adsorption and description of key chemical and flow properties, and a history match of the core flood test results. In addition, preliminary simulation studies were performed, which demonstrated the recovery potential of polymer flooding.
Two modified, low-molecular weight HPAM polymers were tested and have suitable viscosifying power in injected seawater (41 g/mL TDS) at 100°C. The long-term thermal stability results showed that only the more salt-tolerant polymer is stable at 100°C and retains >80% of initial viscosity at 300 days. The stable polymer was tested in a series of single-phase core floods to evaluate transport through low-permeability (5-10 mD) reservoir cores at 100°C. A novel pre-shearing method was developed where pre-sheared polymer solution with 30% of its original viscosity (~3 cP) transported without significant plugging. Finally a high-pressure live-oil two-phase oil recovery coreflood in preserved reservoir core was performed. The incremental oil recovery with three PV's of polymer solution injection was approximately 17% OOIP. Pressure drop was 47 psi/ft., ~3-5 times higher than that of waterflood, for the 3 cP polymer solution. The polymer breakthrough times and resistance factor were reasonable with no evidence of plugging or injectivity issues considering permeability and viscosity of fluids. The polymer retention was measured to be 150 ± 50 μg/g rock, which is higher than a traditional HPAM flood in high-permeability sandstone rock.
The laboratory results obtained thus far are promising considering very harsh and challenging reservoir conditions. The study also highlights an "up-scaleable" pre-shearing method for field application. In the simulation study, a sector model with representative geological features was taken from the full-field simulation model. Measured physical properties from the laboratory evaluation were used as input for the polymer flood simulation. Recovery uplift from polymer flood was found to be ~5% OOIP with significant reduction in water production and reasonable chemical utilization of <10 lbs. per incremental barrel. The simulation study demonstrated promising potential of polymer flooding for the targeted reservoir.
Curren, Morgan (Clariant Oil Services) | Kaiser, Anton (Clariant Oil Services) | Adkins, Stephanie (Ultimate EOR Services LLC) | Qubian, Ali (Kuwait Oil Company) | Al-Enezi, Huda (Kuwait Oil Company) | Sana, Heba (Kuwait Oil Company) | Al-Murayri, Mohammed (Kuwait Oil Company) | Delshad, Mojdeh (Ultimate EOR Services LLC)
Enhanced oil recovery methods are appealing to increase oil recovery from reservoirs due to market pressures in times of lower oil price. Chemical enhanced oil recovery (cEOR) methods such as ASP involve the use of alkali, surfactant, and polymer, to create an ultralow interfacial tension (IFT) between microemulsion and oil phases. These chemicals have the potential to interact with asphaltenes in crude oil and may cause either a decrease or an increase in asphaltene deposition. This paper presents an investigation into the effects of ASP chemicals on asphaltene precipitation.
Crude oil, from a cEOR-nominated Kuwaiti reservoir, was analyzed with an ASP formulation that was determined through microemulsion phase behavior experiments. Crude oil, chemical components, and incompatible solvent were added together, and light transmission was measured over a 15-minute period to determine asphaltene precipitation over time.
A blank graph of the crude in incompatible solvent showed a light transmission increase of 36.2% over the test duration indicating asphaltene precipitation. If asphaltenes remain suspended in oil, light transmission remains low and stable from the beginning to the end of the test. Addition of asphaltene inhibitor (AI) to the crude oil prevented asphaltene flocculation which was evidenced by a maximum light transmission of 3.0%, an efficiency of 91.7% dispersability relative to the blank sample. With addition of the ASP formulation, light transmission increased which indicates interaction between (1) chemical species of the ASP formulation with asphaltenes or (2) the alkali in the chemical package altering the pH and causing more asphaltene precipitation from suspension in the crude. Maximum light transmission of oil dosed with the chemical additives is 41.3% which is a decrease in asphaltene inhibition efficiency of 14.1% relative to the blank. With the addition of AI to the crude containing the chemical additives, the maximum light transmission is 6.5% indicating an efficiency of 82% asphaltene dispersability. Results indicate a clear relationship between addition of ASP chemicals and asphaltene precipitation. Conditions will differ for other crude oils and cEOR formulations, but asphaltene scaling issues should be considered for cEOR projects.
Qi, Pengpeng (Kemira Chemicals, LLC) | Lashgari, Hamid (University of Texas at Austin) | Luo, Haishan (University of Texas at Austin, TOTAL) | Delshad, Mojdeh (University of Texas at Austin) | Pope, Gary (University of Texas at Austin) | Balhoff, Matthew (University of Texas at Austin)
Experimental data in numerous publications show that viscoelastic polymers can significantly reduce residual oil saturation under favorable conditions. The effect of viscoelasticity is in addition to improved sweep efficiency of polymer flooding. The residual oil saturation decreases with increasing dimensionless Deborah number (a measure of the relative elasticity). We used these extensive coreflood data to develop a new model that is referred to here as an Elastic Desaturation Curve (EDC). The new EDC model was implemented into a reservoir simulator and used to simulate polymer floods at both the lab and field scales. The simulated coreflood results match the experimental oil cut, oil recovery and pressure drop data. The simulator was then used to predict the effectiveness of polymer floods in a quarter five-spot well pattern under favorable field conditions. The field-scale simulations show that a viscoelastic polymer flood can recover significantly more oil (12% OOIP for the base case simulation) compared to an inelastic polymer flood of the same polymer viscosity. A sensitivity analysis shows that polymer concentration, salinity, well spacing, permeability, heterogeneity and injection rate affect the incremental oil recovery due to elasticity. The results suggest that the use of viscoelastic polymers could be a beneficial enhanced oil recovery strategy at the field scale under favorable conditions.
One major concern for Alkaline Surfactant Polymer (ASP) flooding is the possibility of inorganic scale formation near the wellbore and in the production facility. In this process, the precipitation reactions of multivalent hardness ions present in the carbonate reservoirs with alkalis in high pH brines might damage the formation, production facilities, and cause severe flow assurance issues. Therefore, it is crucial to understand the geochemical reactions and possibility of scale formation and its associated problems to develop mitigation plans. In this paper, we performed geochemical simulations to investigate the likelihood of inorganic scale formation during ASP flooding in a 5-spot pilot project in one of the largest carbonate reservoirs in the Middle East.
We used a coupled chemical flooding simulator and geochemical (IPhreeqc) framework for this study. First, we incorporated published laboratory data in a geomodel realization of the pilot area. Second, we used the pilot model to investigate the possibility of scale formation during ASP flooding considering a comprehensive system of reactions. Using IPhreeqc, we were able to include thermodynamic databases with various geochemical reactions and capabilities such as saturation index calculation, reversible and irreversible reactions, kinetic reaction, and impacts of temperature and pressure on reaction constants and solubility products. Thus, we were able to show how and where the scales may form.
Our results indicated that the mixing of very hard formation water or water from the subzones near the production wellbore with the injected alkaline water causes scale deposition. We observed calcite dissolutions with slight increase in pH near the injection wellbores after soft seawater preflush. As the ASP solution was injected and high pH brine propagated, carbonate scale and to a lesser extent hydroxide scale formed near the producer. Moreover, although some carbonate and magnesium hydroxide deposits in the formation, but there was negligible effect on reservoir properties. Furthermore, according to our simulation results, most of the scales deposited near the production wellbore, which increases the chance of reducing wellbore productivity and production system damage. These results can help in developing mitigation strategies i.e. preflood the reservoir with soft brine before introducing the ASP slug and optimize the soft brine injection time.
To the best of our knowledge, this is the first study that a comprehensive chemical flood reactive transport simulator is used to assess scale formation during ASP flooding in a carbonate reservoir. Our approach can be used to identify and mitigate challenges and associated design problems for field-scale ASP scenarios.
Driver, Jonathan W. (Ultimate EOR Services and University of Texas) | Britton, Chris (Ultimate EOR Services) | Hernandez, Richard (Ultimate EOR Services) | Glushko, Danylo (Ultimate EOR Services) | Pope, Gary A. (University of Texas) | Delshad, Mojdeh (Ultimate EOR Services)
Water soluble polymers have been used for decades as mobility control agents for tertiary recovery processes. Viscosity is conferred by the large hydrated size of the individual high molecular weight polymer molecules; their single-molecule hydrated size is so large that it can rival the diameters of the pore throats conducting the fluid, and it is widely understood that there are permeability limits below which solutions of such polymers cannot transport well. Delineating exactly where these limits are remains challenging, and operators are left to use whatever anecdotal evidence is available to decide whether to inject polymer, and, if so, what type and molecular weight to use. A rule of thumb is that when the permeability of a rock falls below 100 millidarcys, transport can be problematic.
We have developed processing techniques for laboratory tests to condition polymer solutions for injection into reservoir carbonate cores with permeabilities below 10 millidarcys and median pore radii below one micron. Shearing and tight filtration were used to reduce the maximum size of polymers in solution while retaining as much viscosity as possible. Subsequent filtration was used to quantitatively assess the plugging behavior of the product solution across a range of pore sizes smaller than those which conduct in the rock sample. Coreflood injectivity tests revealed the onset of face plugging as a function of average polymer size. Co-solvent was shown to dramatically improve the transport of sulfonated polyacrylamides when face plugging did not occur, and those improvements were mirrored in benchtop filtration data. This improvement came despite equal-or-better viscosity in the polymer solution, demonstrating that the co-solvent did not reduce the polymer's hydrated size and therefore most likely weakens inter-molecular associations in solution. In sum, the data indicate that permeability loss occurred by two mechanisms: simple mechanical plugging and progressive adsorption, likely mediated by inter-molecular entanglements. These two permeability reduction mechanisms should be rectified by different means.
One major concern for high pH Alkaline Surfactant Polymer (ASP) flooding is the possibility of inorganic scale formation near the wellbore and in the production facility. The precipitation reactions of multivalent hardness ions such as calcium and magnesium present in the carbonate reservoirs with sodium carbonate and sodium hydroxide added to the softened injection brine might cause formation damage and flow assurance issues. Therefore, it is crucial to understand the geochemical reactions and possibility of scale formation and its associated problems to develop mitigation plans. In this paper, we performed geochemical simulations to investigate the likelihood of inorganic scale formation during mixed alkalis and surfactant/polymer flooding in a 5-spot pilot project in a carbonate reservoir.
We used a coupled chemical flooding simulator and geochemical tool for our study. First, we incorporated published phase behavior, and coreflood results in a simulation model of the 5-spot pilot scale. We then used the model to assess the possibility of scale formation considering a comprehensive set of reactions based on ions present in formation brine, injection brine, and the minerology of the reservoir rock. We used IPhreeqc thermodynamic database with various reactions and capabilities such as saturation index calculation, reversible and irreversible reactions, and impacts of temperature and pressure on reaction constants and solubility products. This paper presents a comprehensive chemical flood reactive transport framework to assess inorganic scale formation during very high pH SP flooding using a mix of sodium hydroxide and sodium carbonate in a carbonate reservoir.
Al-Qattan, Abrar (Kuwait Oil Company) | Sanaseeri, Abbas (Kuwait Oil Company) | Al-Saleh, Zainab (Kuwait Oil Company) | Singh, B.B. (Kuwait Oil Company) | Al-Kaaoud, Hassan (Kuwait Oil Company) | Delshad, Mojdeh (Ultimate EOR Services, LLC) | Hernandez, Richard (Ultimate EOR Services, LLC) | Winoto, Winoto (Ultimate EOR Services, LLC) | Badham, Scott (Chemical Tracers, Inc.) | Bouma, Chris (Chemical Tracers, Inc.) | Brown, John (Chemical Tracers, Inc.) | Kumer, Kory (Chemical Tracers, Inc.)
The Greater Burgan Field, first discovered in 1938, is the second largest oilfield in the world. Production from the Greater Burgan began in 1946 from the Wara reservoir via primary recovery. Recently, field-wide waterflood as a secondary recovery mechanism has been implemented. The current insight on the potential of hybrid low salinity water and polymer flooding in the Greater Burgan is presented.
The goal of the Greater Burgan Study team in this enhanced oil recovery (EOR) evaluation program was to compare the benefits of using low salinity waterflood (LSW) and low salinity polymer (LSP) injection as tertiary oil recovery methods in the Wara sandstone reservoir of the Greater Burgan field. The efficacy of low salinity and low salinity polymer injection has been investigated in the laboratory and by conducting a series of single-well chemical tracer (SWCT) tests in one Wara producer.
In the field trial carried out on Well A, three separate determinations of residual oil saturation (Sor) were made. The first SWCT test measured waterflood Sor after injecting a slug of high salinity water (HSW) that is compositionally comparable to the produced water utilized field-wide for waterflooding operations. The second and third SWCT tests measured the remaining oil saturation after LSW and LSP, respectively. Laboratory corefloods were also performed to evaluate LSW and LSP recoveries and their impacts on injectivity. The injection water salinity, injection design, oil viscosity, and polymer viscosity used in the laboratory experiments were identical to those used in the field SWCT tests.
These SWCT test trial results establish a baseline waterflood Sor (i.e., after high salinity water injection) and show that further reductions in Sor may be achieved with low salinity waterflooding and low salinity polymer injection. The laboratory results showed no plugging or injectivity issues during LSW or LSP corefloods. Overall, LSW and LSP were shown to be technically workable tertiary processes in the Greater Burgan.
Foam has been successfully used in the oil industry for conformance and mobility control in gas-injection processes. The efficiency of a foam-injection project must be assessed by means of numerical models. Although there are several foam-flow models in the literature, the prediction of foam behavior is an important issue that needs further investigation. In this paper, we estimate foam parameters and investigate foam behavior for a given range of water saturation by use of two local equilibrium foam models: the population balance assuming local equilibrium (LE) model and the University of Texas (UT) model. Our method uses an optimization algorithm to estimate foam-model parameters by matching the measured pressure gradient from steady-state foam-coreflood experiments. We calculate the effective foam viscosity and the water fractional flow by use of experimental data, and we then compare laboratory data against results obtained with the matched foam models to verify the foam parameters. Other variables, such as the foam texture and foam relative permeability, are used to further investigate the behavior of the foam during each experiment. We propose an improvement to the UT model that provides a better match in the high-quality regime by assuming resistance factor and critical water saturation as a linear function of the pressure gradient. Results show that the parameter-estimation method coupled with an optimization algorithm successfully matches the experimental data by use of both foam models. In the LE model, we observe different values of the foam effective viscosity for each pressure gradient caused by variations of foam texture and the shear-thinning viscosity effect. The UT model presents a constant effective viscosity for each pressure gradient; we propose the use of resistance factor and critical water saturation as a linear function of the pressure gradient to improve the match in the high-quality regime, when applicable.
Jabbar, Muhammad Y. (Zakum Development Company) | Al Sowaidi, Alunood (Zakum Development Company) | Al Obeidli, Amna (Zakum Development Company) | Willingham, Thomas W. (Zakum Development Company) | Britton, Chris (Ultimate EOR services) | Adkins, Stephanie (Ultimate EOR services) | Delshad, Mojdeh (Ultimate EOR services) | Xiao, Rong (ExxonMobil Upstream Research Company) | Teletzke, Gary F (ExxonMobil Upstream Research Company)
The super-giant offshore carbonate oil field started production in 1968 and has been under pattern water flood since 1982. The field is undergoing a major redevelopment utilizing artificial islands and maximum reservoir contact 10,000 ft horizontal wells in a 1:1 line drive. As part of the re-development, Chemical EOR (CEOR) is being assessed for potential application in one of the main oil producing reservoirs. This paper reports on laboratory results of a CEOR study addressing the major challenge of chemical retention in carbonate reservoirs and investigates the feasibility of increasing oil recovery through CEOR processes.
In this paper, CEOR processes investigated include surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) for temperature of 100°C, formation salinity of 200K ppm total dissolved solids, hardness of 15K ppm, and reservoir permeability of <10 mD. In the screening and optimization process, more than 100 surfactant formulations and 3,000 pipette tests at ambient pressure and reservoir temperature utilizing surrogate oil were completed to identify two potential formulations: a SP and an ASP which were stable under reservoir conditions. The polymer qualification includes the polymer rheology and transport tests in reservoir cores using different polymer molecules (HPAM, AMPS), pre-shearing rates, and co-solvent types and concentrations. The identified high-performance SP and ASP formulations were further tested in two live oil corefloods where oil recovery and retention were evaluated. A history match of the core flood experiments was performed and input data were obtained for large scale simulations.
The chemical formulation design results showed that an SP formulation having high solubilization ratio can be prepared in Arabian Gulf seawater. Large-hydrophobe alkoxy carboxylate surfactant and sulfonate cosurfactant showed promising performance for the given harsh reservoir conditions. Polymer injectivity core flood tests were also performed to assess transport of the identified polymers. Results indicate that the pre-sheared viscous polymer solution transported without plugging or filtering out in a 1 -ft long 6 mD composite core. The live oil corefloods of the SP and ASP formulations resulted in an overall recovery factors of 97% and 93.5%, respectively. However, surfactant retention was high at 0.99 and 0.58 mg surfactant/g rock for the SP and ASP core floods under similar injected PV of chemicals. The analysis of the surfactant retention indicates phase trapping and adsorption on minerals are believed to be the dominant mechanisms for most of surfactant retained in the core.
The current study represents a continued expansion of industry experience and includes the identification of two high-performance surfactant formulations which are stable and provide ultra-low IFT under the high temperature, high salinity, and high-hardness characteristic of Middle East carbonate reservoirs.
The upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach hinders effective reservoir simulation and optimization of heavy-oil recoveries by use of waterflood, polymer flood, and other chemical floods, which are inherently unstable processes. The difficulty in scaling up unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations.
Extensive experimental data in water-wet cores indicate that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named “viscous-finger number” in this paper), a combination of viscosity ratio, capillary number, permeability, and the cross-sectional area of the core. On the basis of the features of unstable immiscible floods, an effective-fingering model is developed in this paper. A porous-medium domain is dynamically identified as three effective regions, which are two-phase flow, oil single-phase flow, and bypassed-oil region, respectively. Flow functions are derived according to effective flows in these regions. Model parameters represent viscous-fingering strength and growth rates. The new model is capable of history matching a set of heavy-oil waterflood corefloods under different conditions. Model parameters obtained from the history match also have power-law correlations with the viscous-finger number. This model is applicable to water-wet reservoirs; it has not been tested for mixed-wet and oil-wet systems, low-interfacial-tension (IFT) environments, low permeability, and heavy-oil reservoirs with free gas cap.
In reservoir simulations, having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous-finger number. The model was first applied to a heavy-oil field case with channelized permeability by waterfloods. Simulation results with the new model indicated that viscous fingering strengthened the channeling. Also, the new model shows that a lower injection rate leads to a higher oil recovery. In contrast, oil recovery in waterflooding of viscous oils is overpredicted by classical simulation methods that do not incorporate viscous fingering properly. We further showed that coarse grid simulations with the new model were able to obtain saturation and pressure maps consistent with fine-grid simulations. The new model was then used to model a real field case in the Pelican Lake heavy-oil field. It was able to match the field-production data without major adjustment of reservoir/fluid properties from the literature, showing its competence in capturing subgrid viscous-fingering effects. Overall, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy-oil reservoirs, and hence can facilitate the optimization of heavy-oil enhanced-oil-recovery (EOR) projects.