Reyadh A. Almehaideb

EOS tuning to model full field crude oil properties using multiple well fluid PVT analysis

Abstract Equations of State (EOS) are increasingly being used to model fluid properties of crude oil and gas reservoirs. This technique offers the advantage of an improved fluid property prediction over conventional black oil models. Once the crude oil or condensate fluid system has been probably characterized, its PVT behavior under a variety of conditions can easily be studied. This description is then used, within a compositional simulator, to study and choose among different scenarios for EOR schemes, such as miscible gas injection for oil reservoirs or liquid recovery under lean gas injection for condensate reservoirs. In this paper, crude oil from a reservoir in the United Arab Emirates (UAE) was characterized using the Peng–Robinson Equation of State (PR-EOS) to arrive at one EOS model that accurately describes the PVT behavior of crude oil produced from the different wells in the reservoir. The multi-sample characterization method is used to arrive at one consistent model for crude oil for the whole reservoir. The fluid samples are first analyzed for consistency to make sure that they are representative of oil produced, and then they are used to obtain parameters for EOS model. The tuning procedure for the EOS is done systematically by matching the volumetric and phase behavior results with laboratory results. Also, a consistent C 7+ pseudo-component split using the Whitson splitting method is used for all samples to arrive at a consistent model for crude oil for the whole reservoir. Results showed a very good match of PVT properties predicted using the EOS model with laboratory tests for this field. These results demonstrate the usefulness of the multi-sample method in providing one EOS model for the crude oil using PVT test results from different wells. The EOS model developed for this particular field may be used in reservoir simulation studies to optimize hydrocarbon recovery.

Computer simulation of BTEX emission in natural gas dehydration using PR and RKS equations of state with different predictive mixing rules

Abstract A typical natural gas dehydration plant, which employs triethylene glycol (TEG) as the dehydrating agent, is simulated using a steady state flowsheeting simulator (Aspen Plus). All major units were included in the flowsheet, that is: absorption column, flash unit, heat exchangers, regenerator, stripper, and reboiler. The base case operating conditions are taken to resemble field data from one of the existing dehydration units operating in the United Arab Emirates (UAE). To explore effects of the thermodynamic model employed in the simulator on the reliability of the whole simulation process, different predictive mixing rules applied to two cubic equations of state (EOS), as programmed by the simulator, have been investigated. The EOS used in the simulation is the Redlich–Kwong–Soave (RKS) and the Peng–Robinson (PR), both with Boston–Mathias (BM) alpha function. In addition to the classical empirical mixing rules, the following ones are investigated: Predictive Soave–Redlich–Kwong–Gmehling (PRKS), Wong–Sandler (WS), and Modified-Huron–Vidal (MHV2) mixing rules. These mixing rules are all predictive in nature. The plant performance criteria that have been studied for their response to changes in the solvent circulation rate include: BTEX (benzene, toluene, ethyl benzene, and xylenes) emissions rate, desiccant losses (makeup), water content in the dehumidified natural gas, purity of the regenerated TEG, and reboiler heat duty. Comparison with the field data is done. Very diverse results have been obtained from the different models and mixing rules. No one single model gives the best results for all criteria.

Project of Increasing Oil Recovery from UAE Reservoirs Using Bacteria Flooding

Due to the recent decline in oil prices, most of the enhanced oil recovery (EOR) processes, and especially the ones typically recommended for light crude such as micelles, polymer, or miscible gas injection processes have become economically unattractive. The oil industry currently is in dire need of a reasonable cost process that can both technically and economically be successful. For this reason, a tremendous amount of research effort was directed at UAE University to investigate the possibility of using bacteria, which is a minor cost material, to improve the oil recovery in UAE oil reservoirs. This project focused initially on the study of the interfacial tension (IFT) between crudes from four different UAE reservoirs (BH, UZ, St, and UAD) and a thermophilic bacteria solution. The bacteria were obtained from local water tanks. The system temperature was varied between 30°-100°C and salinity ranged from 0 to 100,000 ppm. Tertiary bacteria solution core flooding experiments were then performed using carbonate rocks at reservoir conditions without injection of nutrient with the bacteria during the core flooding experiments. A good amount of effort was directed, throughout the work, to characterize the bacteria used and identify the mechanism by which bacteria works to improve the oil recovery. Results of these laboratory studies show an abrupt reduction in IFT at high salinity and high temperature (i.e. reservoir condition) for all studied systems except for the St crude, which was sulfur rich. The IFT decreased from 40 dynes/cm to 0.07 dynes/cm for most of the studied systems. Also, tertiary bacteria flooding at reservoir conditions, on average, resulted in an incremental oil recovery of 15 to 20% of the pore volume.

Improved K-values correlation for UAE crude oil components at low pressures using PVT laboratory data

Abstract Several techniques are available in the literature to estimate the K-values. In this paper, results of PVT analysis for 22 crude oil samples from different reservoirs in UAE are used. Sixty-eight single-stage flash laboratory experiments were conducted for these samples. Material balance techniques were used to extract the K-values of crude oil components. These K-values were then correlated and compared with values obtained from published correlations. Comparisons show that current correlations, while they generally give good results for light hydrocarbons in addition to carbon dioxide and hydrogen sulfide, give widely different results for nitrogen and the heptane-plus pseudo-component. Average absolute deviations in excess of 1000% were observed for nitrogen and in excess of 500% were observed for heptane-plus when current methods were used. The proposed new correlation improves significantly the average absolute deviation for both the heptane-plus fraction and for nitrogen, in addition to improving relatively the average absolute deviation for the C1–C6 hydrocarbons, H2S, and CO2. The average absolute deviation for all components was reduced to 28.6% in the new correlation compared to 240% for the Standing correlation and 156.8% for the Wilson correlation. As a test for reliability of the new correlation, bubble point pressures were calculated for 10 samples. The average absolute error for the proposed correlation was 5.2% compared with 6.9% for the Standing correlation, 16.1% for the Wilson correlation, and 7.3% for the Peng–Robinson equation of state.

Microbial and Waterflooding of Fractured Carbonate Rocks: An Experimental Approach

Abstract Fractures and fractured zones require special attention while formulating a reservoir development plan. They may improve or hinder the oil production. Conductive fracture rocks may provide the required permeability to drain an oil saturated low permeability rock matrix. Low sweep efficiency of many oil reservoirs is the result of channelling of injected water through high permeability zones that are normally associated with naturally fractured systems in heterogeneous reservoirs. In this case, a substantial amount of effort needs to be focused on improving the distribution of injected water in the wellbore through different treatments, such as using gelling agents, cements, cross-linked polymer and emulsions. Other alternatives such as microbial and surfactant based methods have been proposed. This paper presents the results of research conducted on thermophilic bacteria that were obtained from UAE local environment. Coreflooding experiments were conducted on fractured single cores to show the effectiveness of microbial treatment. Different fracture angle orientations of 45°, 90°, and 180° relevant to the axis of the flow were investigated. The effect of matrix permeability on the treatment was also studied. A comparison between water flooding and microbial flooding of fractured systems was conducted. A non-invasive imaging technique—Scanning Electron Microscopy (SEM)—was employed to visualize changes on the surface of the fracture as a result of bacteria flow through the system.

Improved Correlations for Fluid Properties of UAE Crude Oils

Abstract Empirical correlations to evaluate crude oil fluid properties such as the formation volume factor, bubble point, viscosity, and oil compressibility above the bubble point are used extensively by petroleum and process engineers to perform calculations for subsurface and surface processes. The published correlations are mostly based on regional data, such as Standings for California crudes, Petrosky and Farshads for Gulf of Mexico crudes, and Glasos for North Sea crudes. Use of these regional correlations is more appropriate for crudes from the same basins for which the correlation is derived. Other correlations, such as the Vasquez and Beggs correlation, are based on data from a very large number of samples coming from multiple regions. Eventhough one is tempted to use these “universal” correlations, the range of error for their predictions is, however, typically large due to the scatter involved in using a large number of data sets to generate these correlations. The UAE fields are quite significant and constitute around 9% of worldwide reserves. In this work, experimental PVT measurements from 15 medium to large fields located in the UAE are used to test the viability of using either regional or universal correlations to UAE crudes. In addition, a new set of empirical correlations is constructed based on these data, and their predictions are also compared. Statistical comparisons indicate that the new correlations developed in this paper reduce the error involved in predicting the bubble point pressures, the oil compressibility, and the oil formation volume factor to less than half the range associated with either the regional or the universal correlations. Also, new correlations for viscosity both at the bubble point and above the bubble point were constructed that gave better predictions for UAE oils over other commonly used correlations for viscosity.

Relative Permeability Measurements of Composite Cores—An Experimental Approach

Abstract Some experimental tests require floods to be carried out on longer cores, typically 1–3 feet long. When whole cores are not available, side-wall cores each measuring 3–6 inches long are put together to make a composite core. It is the prevailing practice in the industry for composite core floods to order cores in an ascending permeability order, as this is thought to lower capillary forces for high flow rates and thus lessen the capillary end-effect. Langaas et al. (1998) have demonstrated through a theoretical study that a new criteria for composite core ordering should be followed (i.e., ordering cores in a descending order). In this work, we present results of an experimental composite core flooding study that was designed to test how the properties of the individual cores in a composite core-stack influence the measured residual oil saturation and relative permeabilities for an oil–water system typical of a water flood. The study was conducted for carbonate cores, predominant in the lower Arabian Gulf region, and involved composite cores stacked in an ascending, descending, and random order (according to the Huppler criteria; Huppler, 1969). Results of the experimental runs in this study show a significant effect of ordering on relative permeability evaluation, with values for K rw and K ro for composite cores in a descending order significantly different from the values for both random ordering and ascending ordering. Also, the recovery factor was highest for the composite core ordered in a descending order, followed by ordering according to Hupplers criteria, and then ascending order. These findings support Langaas et al. findings (i.e., the best ordering criteria is after decreasing permeability along the flow direction such that the core with the highest permeability is placed at the inlet).

Laboratory investigation of parameters affecting optimization of microbial flooding in carbonate reservoirs

ABSTRACT In the laboratory, bacteria have been shown to produce chemicals such as surfactants, acids, solvents, polymers, and gases mainly CO2 1-5 that can significantly contribute to improving displacement and sweep efficiency. Some of these microorganisms can withstand the harsh environ- ment of the oil field and grow at a substantial rate feeding on the organic matter and crude oil itself, thus leading to improvement of oil recovery. Moreover, MEOR process is friendly to the environment. Several field trials have been reported that showed the potential of bacterial enhanced oil recovery (BEOR) in improving oil recovery. Up to date, several investigators have studied the possibility of using microorganism in improving oil recovery, but little work has been reported regarding optimization of the process. As these microorganisms are living organism and it is difficult to predict their behaviour, therefore no attempt has been made to study the parameters that control the process performance. The main objective of this project is to investigate the field parameters that affect the Design of a new process of Microbial Enhanced Oil Recovery in order to achieve optimum oil recovery. In order to reach this goal we must define the factors and field conditions that affect the recovery efficiency of the process and their values that optimize the process. The field parameters considered the most relevant and chosen for this study are the injected bacteria concentration, adaptation time, optimum slug size of bacteria solution, and process application time. The capability of the microbes to transmit through a heterogeneous system and in long cores was also investigated.

Displacement Efficiency of Supercritical CO2 Flooding in Tight Carbonate Rocks Under Immiscible and Miscible Conditions

Carbon dioxide flooding is currently being investigated as possible EOR processes in UAE candidate reservoirs. The major reasons for selecting CO2 flooding as an EOR process were low permeability and heterogeneity of these reservoirs that resulted in poor response to traditional water injection. In this study, immiscible CO2 displacement efficiency of low permeability carbonate rocks of a selected UAE field is evaluated experimentally. Laboratory tests were conducted on seven tight cores extracted from the selected oil field with a permeability range from 0.16 to 11.99 mD and porosity range from 7.72 to 18.63%. The effects of pressure, permeability, and initial oil saturation on the residual oil saturation after flooding at immiscible conditions were investigated in this study. The pressure was varied from 1600 to 4000 psi, and permeability was varied from 0.16 to 11.99 mD at constant pressure of 1600 psi. All runs were conducted at isothermal condition of 127 oF while the initial oil saturation ranged from 0.334 to 0.79 % pore volume. Experimental results indicated that immiscible supercritical (SC) CO2 is capable of mobilizing oil in the very low permeability environment (0.16 mD) with reasonable displacement efficiency. Also, higher displacement efficiencies could be obtained if we start the flooding process earlier, i.e. at higher oil saturation, as there is a critical starting oil saturation required to optimize the displacement efficiency. Side effects from the process are that notable asphaltene precipitation was observed and SC CO2 injection in limestone cores results in the precipitation of calcite in the downstream area. Scanning Electron Microscope (SEM) was used to provide accurate description of pores prior and post CO2 flooding experiments and Energy Dispersive X-Ray Spectrometer (EDS) was used to evaluate the composition of the deposited asphaltene.

A New Approach of Reservoir Description of Carbonate Reservoirs

This study is conducted to test and evaluate the use of current methods of reservoir characterization, namely the permeability-porosity correlation, the J-function, and the Reservoir Quality Index (RQI) concepts, for reservoir description of heterogeneous carbonate formations. These approaches were compared with a new technique developed in this paper for improved reservoir description of carbonate reservoirs. This technique is called the Characterization Number (CN) technique and it is based upon considering fluid, rock, rock-fluid properties and flow mechanics of oil reservoirs. To compare these reservoir characterization techniques, measurements of porosity, absolute permeability, oil and water relative permeability and irreducible water saturation for 83 actual core samples extracted from eight different wells for a new oil reservoir in the U.A.E. are obtained. These experimental data are used first to develop a permeabilityporosity correlation. Then, the J-function and the RQI concepts along with the newly developed CN approach are applied and evaluated for reservoir description of the UAE carbonate reservoir under investigation. The results show that the Reservoir Quality Index concept is capable of identifying the flow units while the J-function concept is quiet poor. Also, a more refined identification of flow units is obtained by using the newly-developed Characterization Number. This improved description for the Characterization Number approach may be attributed to the consideration of rock/fluid properties of flowing fluid(s) and flow dynamic conditions of its containing formation.