Abdulrazag Y. Zekri

Effect of salinity and temperature on water cut determination in oil reservoirs

In this study, system stability and water cut were evaluated via IR analysis and physicochemical properties of the tested mixture. Samples were prepared with different water cuts at a specified salinity and tested by IR. Different cations were also used in the water portion of the mixture to evaluate its effect of interaction and stability. In addition, the effect of water cut, temperature, salinity and cation type, and composition on specific gravity, API gravity, kinematic and dynamic viscosities and surface tension were investigated. The studied water content range was from 0 to 0.8 while temperature from 20 to 100 °C. Salinity effect up to 40,000 ppm was also evaluated. For each mixed ion solution, equivalent sodium concentrations and mixture resistivity were calculated. Relationships between water cut, major functional groups and mixture physicochemical properties were developed. Therefore, for a known property, water cut could be predicted.

Formation Damage Due To Simultaneous Sulfur and Asphaltene Deposition

Summary Although many oil reservoirs are producing crude oils of different sulfur and asphaltene contents, deposition problems of sulfur and asphaltene components in porous media are investigated separately. The major objectives of this laboratory study are to investigate the simultaneous deposition of sulfur and asphaltene in porous media. To achieve these objectives, the influences of the following on the permeability damage of the reservoir rock were experimentally investigated: (1) crude-oil flow rate, (2) permeability of reservoir rock through which crude oil flows, and (3) concentrations of sulfur and asphaltene in the crude oil. A base run was conducted using the crude oil after removing sulfur and asphlatene. Ten dynamic flow experiments were carried out using different crude oils of different sulfur and asphaltene concentrations and under different flow rates. The crude oil was flooded through different rock permeabilities of 2.34, 6.23, 16.58, and 21.48 md and under different flow rates of 0.5, 1.0, 2.0, and 3.0 cc/min, respectively. No permeability reduction or pore plugging was measured for the base experiment. The results indicated that the increase of flow rate increases the formation damage because of simultaneous deposition of sulfur and asphaltene in the reservoir rock. Core samples of lower permeability showed more severe permeability damage than those of higher permeability for the same applied flow rate and the same sulfur and asphaltene content of the crude oil. Furthermore, the increase of asphaltene and/or sulfur content of the crude oil increases the rock damage. The attained results of this study highlighted the important role of formation damage of carbonate oil reservoirs containing oils with a considerable amount of sulfur and asphaltene. In addition, the study provides two empirical correlations capable of predicting the permeability damage rate as a function of flow rate or initial rock permeability. These correlations represent useful tools for semianalytical and simulation studies.

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.

Effect of Temperature on Biodegradation of Crude Oil

An active strain of anaerobic thermophilic bacteria was isolated from the environment of the United Arab Emirates. This project studied the effect of temperature, salinity and oil concentration on biodegradation of crude oil. Oil weight loss, microbial growth and the changes of the crude oil asphaltene concentration are used to evaluate the oil degradation by this strain. A series of batch experiments was performed to study the effects of bacteria on the degradation of crude oil. The effects of oil concentration, bacteria concentration, temperature and salinity on the biodegradation were investigated. The temperatures of the studied systems were varied between 35 and 75°C and the salt concentrations were varied between 0 and 10%. Oil concentrations were ranged from 5 to 50% by volume. Experimental work showed the bacteria employed in this project were capable of surviving the harsh environment and degrading the crude oil at various conditions. Increasing the temperature increases the rate of oil degradation by bacteria. Increasing the oil concentration in general decreases the rate of bacteria oil degradation. Salinity plays a major role on the acceleration of biodegradation process of crude oil. An optimum salinity should be determined for every studied system. The finding of this project could be used in either the treatment of oil spill or in-situ stimulation of heavy oil wells.

A New Technique for Measurement of Oil Biodegradation

Abstract An active strain of anaerobic thermophilic bacteria was isolated from the environment of the United Arab Emirates. The strain, identified as Bacillus species, consists of two types—round and rod-shaped bacteria. This project studied the possibility of using these two types of bacteria for biodegradation of oil under elevated temperature conditions using a new method of measurement. Chemical and physical techniques were used previously to estimate the degradation rate of oil by microbes. In this project, a technique is was used to provide more accurate and reliable measurements. Visual inspection and measurements of oil drop size as a function of time were conducted. A computer image analyzer was used in this study to track bacterial growth and capacity to survive under different environmental conditions. The temperature of the studied systems varied between 25°C and 70°C, and salt (sodium chloride (NaCl)) concentration varied between 0 and 50,000 ppm NaCl. The temperatures were selected to include typical sea water and reservoir temperatures in the Persian Gulf region. The average bacterial concentration used in this study was 182 × 103 cells/mL. Experimental results indicated that the bacteria have the capacity to survive in saline and high temperature environments. The maximum oil degradation was observed at 70°C for all tested salinities. The degradation rate can be maximized by lowering the salinity and increasing the temperature of the studied systems. At a high temperature of 70°C, bacterial growth tends to improve at a low salt concentration, with a maximum oil degradation rate obtained at 10,000 ppm NaCl.

Steam/bacteria to treatment of asphaltene deposition in carbonate rocks

In this project, steam and bacteria were tested to stimulate the damaged limestone cores. Several dynamic experiments were conducted to determine the effect of asphaltene on the permeability of limestone cores. Plugging effects due to asphaltene deposition were evaluated through comparison with reference permeability measured prior to and after oil flow. Damaged cores were subjected to different type of treatments: a steam soak process and bacteria. The permeability of the cores was measured after each treatment. Core impairment resulting from in situ asphaltene deposition, was found to cause an 8% to 93% loss of initial oil permeability depending on rock permeability and injection rate. Core stimulation resulting from steam soak treatment, was found to cause an 18% to 400% improvement on the damaged core permeability depending on rock permeability and soaking time. Core stimulation results from bacteria treatment, was found to cause a 41% to 129% improvement on the damaged core permeability depending on core permeability and the extent of the damage.

The Prediction of Bubble-point Pressure and Bubble-point Oil Formation Volume Factor in the Absence of PVT Analysis

Up to now, there has not been one specific correlation published to directly estimate the bubble-point pressure in the absence of pressure-volume-temperature (PVT) analysis. Presently, there is just one published correlation available to estimate the bubble-point oil formation volume factor (FVF) directly in the absence of PVT analysis. Multiple regression analysis technique is applied to develop two novel correlations to estimate the bubble-point pressure and the bubble-point oil FVF. The developed correlations can be applied in a straightforward manner by using direct field measurement data. Separator gas oil ratio, separator pressure, stock-tank oil gravity, and reservoir temperature are the only key parameters required to predict bubble-point pressure and bubble-point oil FVF.

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.

An experimental approach of influences of perforated length and fractures on horizontal well productivity

Many simulation studies have been conducted regarding the importance of perforated well length on horizontal well performance. All of these studies suffered from their dependence upon theoretical models, which lack plausibility due to the lack of accurate experimental and/or field data. Therefore, there is a real need for experimental data to be used for tuning the single well simulation models before applying a full field simulation of oil reservoirs with horizontal wells. This experimental study was designed to investigate the influences of fractions of perforated length, total length, and fractures, which do not intersect with a well axis, on the productivity of horizontal wells. An experimental model (60 cm · 40 cm · 20 cm) was designed and used to achieve the study objectives. Carefully sized sandpacks were used to represent the homogeneous unconsolidated porous media while a perforated aluminum sheet was used as a horizontal fracture parallel (horizontal fracture) and perpendicular but not intersecting (vertical fracture) the horizontal well axis in the sandpack. Several runs were carried out using horizontal wells with different lengths and different perforation fractions of total length utilizing homogenous porous media with and without fracture systems. The results indicated that an increase of perforated well length increases flow rate of the horizontal well for both homogeneous and fractured formations that do not intersect with the well axis. Furthermore, horizontally-fractured formations parallel to and vertically-fractured formations vertical to the well axis improve the productivity of horizontal wells for different perforation ratios. A single vertically-fractured porous medium provides a higher productivity ratio than a horizontally-fractured one for the same perforation length and intensity, when both fracture systems do not intersect with the well axis. Several empirical equations were developed to correlate the horizontal well productivity with perforated length for homogenous and fractured porous media. Ignoring of the effect of pressure drop along horizontal well may have serious implications on perforated well length since proportionality of the productivity index to the well length is no longer valid. From reservoir and production engineering standpoints, the sole difference between vertical and horizontal wells was identified to be the contact area. For a partially penetrating vertical well, the reservoir disturbance due to a vertical well was limited to the close vicinity of the wellbore hole (8) . Then, the choke diameter became the main parameter affecting the flow rate. For a horizontal well, the disturbance created by the well not only affected the vicinity of the wellbore, but also influences the whole reservoir due to the greater contact area of the pay zone penetrated by the well. In addition, in the case of a horizontal well, there was a non-uniform flow, which basically depends upon the ratio of pressure drop by friction through the horizontal section and pressure drop across the pay formation (9) . For the sake of simplifying theoretical solutions, the pressure gradient through the horizontal section was neglected, which was not true in many cases. The adequacy of using the assumption of infinite wellbore conductivity to describe fluid flow in horizontal wells reveals an argument in the literature. If the pressure drop along the horizontal well was negligible in comparison to the reservoir pressure, this might be a good assumption. In practice, pressure drop along the horizontal section of the well was essential to maintain fluid flow within the wellbore, and therefore cannot be neglected. Folefac et al. (10) pointed out that pressure drop along horizontal wells affected their inflow performance and in many circumstances led to over prediction of productivity index and deliverability of these horizontal wells. They showed in their simulation study that horizontal well parameters such as horizontal well length, diameter, and perforated intervals had the most significant effect on pressure drop level in the wellbore hole. Al Qahtani et al. (9) performed a simulation study to investigate the effect of length and distribution of perforated intervals on horizontal well rates. This study was based upon the productivity index solution of perforation distribution and perforated lengths