A. Shedid

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.

Influences of Different Modes of Reservoir Heterogeneity on Performance and Oil Recovery of Carbon Dioxide Miscible Flooding

Reservoir heterogeneity represents one of the most dominant factors affecting the performance of CO 2 miscible flooding and its expected oil recovery. The main goal of this study is to investigate the influence of different modes of reservoir heterogeneity on oil recovery by supercritical CO 2 miscible flooding. The investigated heterogeneity modes include: 1) different single fractured reservoirs of different inclination angles, 2) different permeability configurations of layered reservoirs, and 3) the sequence of permeability distributions in composite reservoirs. Complete reservoir rock and oil compositional analyses were performed. The minimum miscibility pressure (MMP) of oil-CO 2 was mathematically calculated using several empirical correlations and determined experimentally using slim tube tests. The core flood tests were achieved using actual fluids injected through 12 actual reservoir rock samples. Of these, four samples were of different fracturing angles as single fractured reservoirs, four samples were of different permeability configurations as layered rocks and four samples represented composite reservoirs. The slug size of supercritical CO 2 was optimized to be 0.15 PV, injected and chased by actual reservoir brine through these different simulated modes of reservoir heterogeneity. The results indicated that all different modes of reservoir rock heterogeneity have a crucial influence on oil recovery by CO 2 miscible flooding in carbonate oil reservoirs. Of note, unfractured reservoirs produced higher oil recovery by CO 2 miscible flooding than single fractured ones. An oil reservoir with a 30 degree inclination angle of single fracture produced the highest oil recovery, whereas, fractured rocks with a 45 degree fracture produced the minimum oil recovery in this category. The rock permeability sequences of medium-low-high (MLH) mode for composite reservoirs and medium-high-low (MHL) distribution mode for layered reservoirs are highly recommended for CO 2 miscible flooding. The results have proven the suitability of the CO 2 application for layered and composite heterogeneous carbonate reservoirs, however, it does not recommend this EOR process for single fractured reservoirs. The results have also shown a real impact on oil recovery of the reservoir heterogeneity mode prevailing in the reservoir under development by this EOR process.

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.

Simulation Investigations for Enhanced Performance of Beam Pumping System for Deep High Volume Wells

Worldwide there are almost 920,000 producing oil wells, about 87 % of these wells are operated using different artificial lift methods and roughly distributed as: 71 % are producing using beam pumping system, 14 % using electrical submersible pumping (ESP), 8 % using gas lift and 7 % using all other forms of lifting systems. This study was undertaken using advanced predictive methods, high strength rods, optimum pumping mode, and unit geometry to optimize the performance of beam pumping system for deep high volumes oil wells. Three geometries of different surface pumping units were analyzed and studied including, conventional, Reverse Mark and Mark II units. Each geometry of these three types has been subjected to different design features that affect torque and different linkages affecting its kinematics behavior. The highest strength sucker rod string, beam unit geometry, stroke length, pumping speed and subsurface pump size were varied and analyzed jointly to obtain optimum pumping parameters capable to produce maximum fluid at different well depths. This study considered and applied many variables including; well depths from 1,000 to 15,000 ft, three different rod grades, water cuts from 0.0 to 100 %, different pump sizes from 1.25 to 5.75 in, stroke lengths from 100 to 260-inch, and non-API sucker rod grades. The results indicated that the lifted liquid volumes and pump seating depths for deep wells can be effectively increased using the beam pumping systems. The surface unit geometry has shown a crucial effect of increasing the produced quantity from deep wells. The study recommended using conventional pump unit for shallow depths up to 8,000 ft. The enhanced geometry pumping units of Mark II and reverse Mark have been proven the superior type for deep high volumes wells because it required the least torque to lift the same quantity from different well depths. The study also presented successful field applications for deep wells producing high volumes.

INFLUENCES OF ASPHALTENE PRECIPITATION ON CAPILLARY PRESSURE AND PORE SIZE DISTRIBUTION OF CARBONATE RESERVOIRS

Asphaltene depositio n has profound effects on oil flow through porous medium. The investigation of the influences of asphaltene precipitation on carbonate reservoir rocks has minor interests in comparison to studies investigated sandstones ones. Therefore, this study is undertaken to provide accurate insights, especially for carbonate reservoirs of low permeability. In this study, two groups of experiments are undertaken. The first experimental group investigates effects of asphaltene precipitation on (a) petrophysical properties of carbonate rocks, including absolute permeability, effective porosity, and hydraulic radius, and (b) on oil-water relative permeability and water flooding performance. The second group searches for the effects of asphaltene precipitation on capillary pressure and pore size distribution of low permeability carbonate reservoirs. Conducted experiments are achieved using actual reservoir liquids of crude oil and brine, flowing through actual carbonate cores under similar reservoir conditions of temperature and pressure. The results indicated that asphaltene precipitation damages absolute permeability and hydraulic radius drastically, reduces effective porosity, and improves relative permeability of water for different asphaltene contents of crude oil flowing through carbonate reservoirs. In addition, oil reservoirs of high asphaltene content have shown higher values of irreducible water saturation than that ones of low asphaltene content in their crude oils. Precipitation of asphaltene in carbonate rock causes changes in the position of capillary pressure at high mobile oil saturation and reduces values resulted for pore size distribution curves, especially for small pore radii carrying crudes of high asphaltene content. Neglecting the proven influences of asphaltene precipitation may lead to erroneous description of carbonate reservoirs. Therefore, analysis of petrophysical properties and pore size distribution of carbonate reservoirs has to be updated during the extended life of oil reservoir and based upon accurate values of asphaltene content of the flowing crude oils. Applications of the attained results of this study are expected to provide real improvement in reservoir description, more reliable estimation of oil reserves, accurate predicted values of reservoir rock damage, and also better descriptive functions for future reservoir simulation studies.

Comparison of Chemical Steam Floods through Vertical and Horizontal Wells

Laboratory investigations and field applications have proved steam drive to be an effective enhanced oil recovery method for reservoirs of moderate and heavy oil viscosity. This experimental study was undertaken to investigate, combine and compare the performance and productivity of water, steam, alkaline steam, surfactant steam, and surfactant alkaline steam floods through vertical and horizontal wells. To achieve the objectives of the study, two experimental models (vertical and horizontal) are designed and built. Identical porous media, reservoir fluids (crude oil and formation water), steam, chemicals, and injection/production conditions are used and/or applied. The results of the study showed that horizontal wells are better candidates for waterflooding than vertical ones, when the same pore volume of water are injected in the reservoir. Steam and chemical steam (alkaline steam, surfactant steam, and surfactant alkaline steam) floods recovered more oil when applied through horizontal wells than through vertical ones. In addition, chemical steam floods recover more oil than conventional steam drive for both applications of vertical and horizontal wells. The increment of oil recovery due to application of horizontal wells instead of vertical ones may be 10.27 % IOIP for steam flood and almost 17.7 % IOIP for surfactant alkaline steam flood. The displacement efficiency of oil recovery through horizontal wells is higher than that through vertical wells for steam flood by almost 25 %, for alkaline steam flood by almost 33 %, for surfactant steam flood by almost 37 %, and for surfactant alkaline steam flood by almost 48 %. The proposed techniques of chemical steam floods have important implications for improving oil recovery from current water flood and steam projects, since they combine the advantages of both chemical and thermal recovery methods.

Reversibility of Asphaltene Deposition Under Dynamic Flow Conditions

Abstract Occurrence of asphaltene deposition in production formation constitutes one of the most serious problems currently encountered in the petroleum industry in many areas of the world. Reversibility of asphaltene deposition causes crucial argument and controversy in laboratory research of the petroleum industry. A deeper understanding of this phenomenon is the key for treatment of the problem of asphaltene deposition. The major goals of this study were to investigate 1) asphaltene adsorption rate on carbonate rock surfaces under static condition, and 2) asphaltene deposition and its reversibility under dynamic flow conditions. For the sake of achieving these goals, two groups of experiments were undertaken. The first one measured asphaltene adsorption rate under static condition, while the second group was devoted to studying reversibility of asphaltene deposition under dynamic flow condition through actual porous medium. The results of the study indicated that the increase of aging time increases asphaltene adsorption on carbonate rock surfaces under static condition. However, the major part of asphaltene is adsorbed during the first 30 h of contact of oil with the rock surface. The results of dynamic flow experiments showed that asphaltene deposition is a continuous process causing permeability damage and is also partially reversible. Furthermore, the asphaltene deposition causes more damage in low permeability rock than one in higher permeability. The obtained results are expected to have important implications for better formulation of treatments of asphaltene deposition.

AN EXPERIMENTAL APPROACH OF ELEMENTAL SULFUR DEPOSITION IN CARBONATE OIL RESERVOIRS

ABSTRACT The existence of sulfur compounds in crude oils creates many problems of sulfur deposition in the vicinity of the wellbore hole, in well completion and/or production equipment, and in producing reservoir rocks. The major objectives of this experimental study are to investigate the influences of oil flow rate, initial sulfur concentration of crude oil, and reservoir rock permeability on elemental sulfur plugging in carbonate oil reservoirs. To achieve these objectives, actual crude oils were de-asphaltened to eliminate the effect of asphaltene deposition. Ten dynamic flow experiments were conducted using two actual crude oils of 0.78 and 1.67% sulfur concentrations. Viscosity of crude oils of different sulfur concentrations was measured under different conditions of temperature. The crude oils were flooded through actual carbonate cores of different permeability in the range of 2.34–28.16 millidarcy and under different flow rates of 0.5, 1.0, 1.5, and 2.0 cc/min. In-situ sulfur deposited was measured using Scanning Electron Microscopy (SEM) to provide the amount of sulfur deposited along the core samples. The results indicated that crude oil of higher sulfur concentration has higher viscosity than that of one of lower concentration. The deposition of elemental sulfur does not take place at the low rate of 0.50 cc/min, starts at 1.0 cc/min and increases as the flow rate increases up to 1.50 and 2.00 cc/min, respectively. In addition, the higher sulfur concentration of the crude oil increases the deposition of sulfur in carbonate oil reservoirs. The results also showed that permeability of carbonate reservoir rocks has a severe effect on sulfur deposition since carbonate rocks of higher permeability do not experience the problem of elemental sulfur deposition while the problem is more severe for lower permeability rocks. In addition, the depositional rate is accelerated rapidly as the rock permeability decreases. The obtained results of this study have important interest in identification of the most important factors affecting the elemental sulfur precipitation in heterogeneous carbonate oil reservoirs and robust implications in the development of reservoir simulation models.

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

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.