Shubham, Agrawal (Texas A&M University at Qatar) | Martavaltzi, Christina (Texas A&M University at Qatar) | Dakik, Ahmad Rafic (Texas A&M University at Qatar) | Gupta, Anuj (Texas A&M University at Qatar)
It is well known that the majority of carbonate reservoirs are neutral to oil-wet. This leads to much lower oil recovery during waterflooding since there is no spontaneous imbibition of water in heterogeneous reservoir displacement. It has been verified by a number of researchers that Adjustment of ion concentration in brine solutions, or adding surfactant solutions can enhance the oil recovery by altering the wettability. In the published literature, contact angle studies usually refer to measurement on calcite crystals and there are no results for the contact angle of carbonate porous media representative of reservoir rocks. Moreover, there are few studies on the effect of non-ionic surfactants, compared to those for ionic surfactants. Understanding the effect of various ions and their concentration in the injection brine on the wettability of the Limestone outcrop core samples is the first step for tailoring of the optimum injection brine. This will be followed by a study of the effect of surfactant on the wettability of calcite crystal samples. The evaluation of the results may provide guidelines for the design of injection brines for efficient enhanced oil recovery from carbonate reservoirs.
In this work, a procedure is established for the measurement of the contact angle on limestone outcrop core samples. Results showed that, at atmospheric conditions, low salinity CaCl2 solution induced the most significant improvement on the wettability of the outcrop sample. Moreover, among all the non-ionic surfactants studied, only the presence of the two first members of the 15S analogous series might lead to a slight decrease of the contact angle.
Sanyal, Tirtharenu (Kuwait Oil Company) | Al-Hamad, Khairyah (KOC) | Jain, Anil Kumar (KOC) | Al-Haddad, Ali Abbas (KISR) | Kholosy, Sohib (KISR) | Ali, Mohammad A.J. (Kuwait Inst. Scientific Rsch.) | Abu Sennah, Heba Farag (Kuwait Oil Company)
Improved oil recovery for heavy oil reservoirs is becoming a new research study for Kuwaiti reservoirs. There are two mechanisms for improved oil recovery by thermal methods. The first method is to heat the oil to higher temperatures, and thereby, decrease its viscosity for improved mobility. The second mechanism is similar to water flooding, in which oil is displaced to the production wells. While more steam is needed for this method than for the cyclic method, it is typically more effective at recovering a larger portion of the oil.
Steam injection heats up the oil and reduce its viscosity for better mobility and higher sweep efficiency. During this process, the velocity of the moving oil increases with lower viscosity oil; and thus, the heated zone around the injection well will have high velocity. The increase of velocity in an unconsolidated formation is usually accompanied with sand movement in the reservoir creating a potential problem.
The objective of this study was to understand the effect of flowrate and viscosity on sand production in heavy oil reservoir that is subjected for thermal recovery process. The results would be useful for designing completion under steam injection where the viscosity of the oil is expected to change due to thermal operations.
A total of 21 representative core samples were selected from different wells in Kuwait. A reservoir condition core flooding system was used to flow oil into the core plugs and to examine sand production. Initially, the baseline liquid permeability was measured with low viscosity oil and low flowrate. Then, the flowrate was increased gradually and monitored to establish the value for sand movement for each plug sample. At the end of the test, the produced oil containing sand was filtered for sand content.
The result showed that sand production increased with higher viscosity oil and high flowrate. However, sand compaction at the injection face of the cores was more significant than sand production. In addition, high confining pressure contributes to additional sand production. The average critical velocity was estimated ranged from 18 to 257 ft/day for the 0.74 cp oil, 2 to 121 ft/day for the 16 cp oil, and 1 to 26 ft/day for the 684 cp oil.
Ahmad, Khalid (Kuwait Oil Company) | Ferdous, Hasan (Kuwait Oil Company) | Llerena, Javier (Kuwait Oil Company) | Ahmad, Fatma (Kuwait Oil Company) | Chaudhary, Pradeep (Kuwait Oil Company) | Abbas, Faisal (Kuwait Oil Company) | Sammak, Ibrahim (Kuwait Oil Company)
One pilot study presently being conducted through CSS thermal recovery technology to explore a shallow poorly-consolidated viscous oil bearing sandstone reservoir in Kuwait with extensive integrated reservoir evaluation efforts to optimize the future development strategy.
The reservoir largely consists of two separate deltaic sand packages representing multi-stacked channel facies resulting to stratified reservoir intervals with variable degree of fluid saturations. Reservoir characterization uncovers high matrix contents along with calcite, dolomite, and clays as cements which essentially control uneven pore-geometry that fabricate the petrofacies types into multiple thin stratified-pay intervals, each being < 30' thick with variable fluid saturations resulting from long transitional thief zones posing high risk for thermal recovery. Thus, a seemingly simple channel-based reservoir interval has been greatly altered by diagenetic episodes that need evaluation towards an arduous perforation, completion and production strategy to pursuit the well-defined individual thin pay-interval.
Single-well thermal recovery scheme under "injection-soak-production?? sequence being conducted presently in three vertical wells, each subjected to first cycle injection of moderate quality steam (~75% at 4200 F) at rates 400 to 600 barrels EW/d at about 450 psig injection pressure for 26 to 71 days, followed by a soak period of 10 to 60 days. Subsequent total production estimates SOR between 0.2 and 0.9. In two wells, cumulative oil/water productions and 15% to 34% water cut indicate an excellent response to thermal stimulation. The encouraging injection parameters of steam slug size, high injection rates at low pressures, and subsequent productions provide valuable information towards upcoming second cycle injection and future steam flood strategy.
The ongoing CSS pilot is providing some critical information for the future commercial development phase. As such, all pertinent data are closely evaluated to ensuring the optimal strategy to meet the long-term development plan for this viscous oil asset.
Alomair, Osamah Ali (Kuwait University) | Alarouj, Mutlaq Abdullah (Kuwait University) | Althenayyan, Abdullah Ahmed (Kuwait University) | Al Saleh, Anwar Hassan (Kuwait University) | Almohammad, Humoud (Kuwait University) | Altahoo, Younes (Kuwait University) | Alhaidar, Yousef (Kuwait University) | Al Ansari, Sara Ebrahem (Kuwait University) | Alshammari, Yousif (Kuwait University)
Thermal recovery methods have the objective of accelerating hydrocarbon recovery by raising the temperature of the formation and reducing hydrocarbon viscosities. Thermal recovery involves several well-known processes such as steam injection, in situ combustion, steam assisted gravity drainage (SAGD), and a more recent technique that consists of heating the reservoir with electrical energy. The most common thermal method is steam injection. However, some difficulties occurs with steam injection includes; water availability, the cost of water vaporization process, and how to keep steam temperature above the condensation temperature at reservoir conditions. Also it is limited to relatively shallow, thick, permeable, and homogenous sand reservoirs that are located onshore.
In this project three unconventional thermal approaches were developed in laboratory scale to improve the recovery of heavy oil. Those methods are; electrical resistant electrodes, electromagnetic inductors, and microwaves. Designing and experimenting were prepared using low cost material to achieve the success of the new approaches. In the electrical resistance approach, a potential difference was applied between two electrodes; one act as anode and the other one as a cathode. A sufficient heat has been introduced between the electrodes, which improved the oil recovery by adding a maximum of 21% additional recovery to the primary recovery. For the electromagnetic induction, a coil has been wrapped around a core through which the introduced heat was transmitted to the fluid inside and hence increasing the oil recovery by a maximum of 34%. As for the microwave method, microwaves were applied on the core to vibrate water molecules. These microwaves were created and applied by using normal microwave oven, where the waves were transmitted from the source, and reflected inside an isolating body to prevent any wave leakage. The molecules movement resulted in heat generation and thus a reduction in the oil viscosity. The conducted test revealed an increase of 30% in the oil recovery which varies according to the operating power. Finally, economical comparison between the proposed methods was conducted. The three methods were compared by combining recovery and power consumption. Average power consumption per unit production for electromagnetic induction, Electrical Resistance, and microwave were 39, 2570, and 3.775 watt.hr/cc, respectively. The comparison revealed that the Microwave Heating is the most economical choice followed by electromagnetic induction and finally the electrical resistance heating.
Nghiem, Long X. (Computer Modelling Group Ltd.) | Mirzabozorg, Arash (University of Calgary) | Chen, Zhangxin John (University of Calgary) | Hajizadeh, Yasin (Computer Modelling Group Ltd.) | Yang, Chaodong (Computer Modelling Group Inc.)
History matching of reservoir flow models based only on production data may not reveal deficiencies that affect future predictions. Incorporating saturation and temperature profile data that come from 4D seismic surveys in the history matching process can reduce the uncertainty of reservoir models for the prediction stage. We constructed a field reservoir model from which production history, saturation and temperature profile history were obtained. We started the history matching process with a base reservoir model, the petro-physical properties of which were substantially different than those of the field reservoir model. We propose a new methodology for matching the fluid and temperature profiles by adjusting reservoir petro-physical properties. In this methodology, some grid blocks in a reservoir model were selected judiciously to capture the overall saturation and temperature distribution profiles. In addition to well production data, we included the saturation and temperature profiles at these grid blocks as extra objective functions during the history matching process. The DECE optimization is used to reduce the objective function. We applied this method in a Steam Assisted Gravity Drainage (SAGD) process and matched the saturation and temperature profiles with an average error of less than 2%.
Abou Sayed, Nada (Petroleum Institute) | Shrestha, Reena (The Petroleum Institute) | Sarma, Hemanta Kumar (The Petroleum Institute) | Al Kindy, Nabeela (The Petroleum Institute) | Haroun, Muhammad (University of Southern California) | Abdul Kareem, Basma Ali (The Petroleum Institute) | Ansari, Arsalan Arshad (The Petroleum Institute)
EOR technologies such as CO2 flooding and chemical floods have been on the forefront of oil and gas R&D for the past 4 decades. While most of them are demonstrating very promising results in both lab scale and field pilots, the thrive for exploring additional EOR technologies while achieving full field application has yet to be achieved. Among the emerging EOR technologies is the surfactant EOR along with the application of electrically enhanced oil recovery (EEOR) which is gaining increased popularity due to a number of reservoir-related advantages such as reduction in fluid viscosity, water-cut and increased reservoir permeability.
Experiments were conducted on 1.5?? carbonate reservoir cores extracted from Abu Dhabi producing oil fields, which were saturated with medium crude oil in a specially designed EK core flood setup. Electrokinetics (DC voltage of 2V/cm) was applied on these oil saturated cores along with waterflooding simultaneously until the ultimate recovery was reached. In the second stage, the recovery was further enhanced by injecting non-ionic surfactant (APG) along with sequential application of EK. This was compared with simultaneous application of EK-assisted surfactant flooding. A smart Surfactant-EOR process was done in this study that allowed shifting from sequential to simultaneous Surfactant-EOR alongside EEOR
The experimental results at ambient conditions show that the application of waterflooding on the carbonate cores yields recovery of approximately 46-72% and an additional 8-14% incremental recovery resulted upon application of EK, which could be promising for water swept reservoirs. However, there was an additional 6-11% recovery enhanced by the application of EK-assisted surfactant flooding. In addition, EK was shown to enhance the carbonate reservoir's permeability by approximately 11-29%. Furthermore, this process can be engineered to be a greener approach as the water requirement can be reduced upto 20% in the presence of electrokinetics which is also economically feasible.
The matrix blocks in fractured reservoirs are the primary storage of hydrocarbons, so matrix-fracture transfer mechanisms are of crucial importance in recovery from fractured reservoirs. During gas injection into fractured reservoirs, fractures are filled with injected gas while matrix blocks contain the reservoir fluid. In this condition due to compositional difference between the gas in fractures and the fluid in matrix, diffusive exchanges of components between matrix and fracture may have significant contribution on matrix oil recovery in addition to gravity drainage or other transfer mechanisms.
In this work, to evaluate the significance of molecular diffusion, the laboratory experiment of "Gas Injection into Fractured cores?? is simulated using a compositional model and this model is used to run several experiments which help in understanding the way that each recovery mechanism acts. The advantage of running simulation in core scale is that in this way there is the possibility of using small grid size which significantly reduces the issues of numerical dispersion. And more over the existing experimental data can be used for model adjustment. In the experimental works the procedure is to place a core sample into a core holder in such a way that the annulus space between the core boundary and the core holder is very small. This annulus space is representative of the fracture surrounding the matrix blocks in the reservoir. Then after using special techniques the core is saturated with the representative reservoir oil, and after this primary core initialization, gas is injected into the annulus and the amount of recovered oil is measured versus time.
This study reveals that, molecular diffusion acts like a catalyst and improves the recovery mechanism by enhancing the gas movement within matrix. At the prevalent conditions of this work, the main recovery mechanisms are the miscibility effects (Condensing or Vaporizing gas drives) that are enhanced by molecular diffusion. Sensitivity analysis done in this work reveals that significance and contribution of molecular diffusion in recovery changes with different parameters such as matrix permeability and porosity, gas composition, etc.
Fractured reservoirs contain a significant portion of the world's reserves, and Gas injection is a common recovery practice in these reservoirs and understanding the recovery mechanisms is of crucial importance for correct simulation of this process. This study shows, although significance of molecular diffusion changes with reservoir parameters, any way neglecting it in simulation studies will result in underestimation of gas injection efficiency.
Viscosity and Density are important physical parameter of crude oil, closely related with the whole processes of production and transportation, and are very essential properties to the process design and petroleum industries simulation. As viscosity increases, a conventional measurement becomes progressively less accurate and more difficult to obtain. According to the literature survey, most published correlations that are used to predict density and viscosity of heavy crude oil are limited to certain temperatures, API values, and viscosity ranges. The objective of present work is to propose accurate models that can successfully predict two important fluid properties, viscosity and density covering a wide range of temperatures, API, and viscosities. Viscosity and density of more than 30 heavy oil samples of different API gravities collected from different oilfield were measured at temperature range 15oC to 160oC (60oF to 320oF), and the results were used to ensure the capability of proposed and published correlations to predict the experimental viscosity and density data. The proposed correlation can be summarized in two stages. The first step was to predict the heavy oil density from API and temperature for different crudes. The predicted values of the densities were used in the second step to develop the viscosity correlation model. A comparison of the predicted and actual viscosities data, concluded that the proposed model has successfully predict all data with average relative errors of less than 12% and with the correlation coefficient R2 of 0.97, and 0.92 at normal and high temperatures respectively. Meanwhile, the results of most of the available models has an average relative error above 40%, with R2 values between 0.19 to 0.95. These comparisons were made as a quality control to confirm the reliability of the proposed model to predict density and viscosity values of heavy crudes when compared with other models.
The oil-water interfacial tension (IFT) is by all means important in capillary pressure estimation and fluid-fluid and fluid-rock interactions analysis. Observations from experimental data indicate that oil-water IFT is a function of pressure, temperature, and compositions of oil and water. A reliable correlation to estimate oil-water IFT is highly desire. Unfortunately to our best knowledge no correlation that uses the compositions of oil and water as inputs is available. Our work is to fill this gap.
In this research, we collected data from former studies and investigations and developed a correlation for oil-water IFT. In the proposed correlation oil-water IFT is a function of system pressure, temperature, and compositions of oil and water. Error analysis was conducted to check the accuracy of the equation by comparing the calculated values with the experimental data. The results indicated that the new correlation predicts reliable oil-water IFTs. Our correlation calculates the oil-water IFT from system pressure, temperature, and compositions of oil and water. It addresses the effect of composition of oil on IFT, which is not presented in existing correlations. Therefore it can not only be applied in the calculation of capillary pressure in the compositional simulation, but also be used in daily petroleum engineering calculation such as waterflooding analysis.
Significant advances have been made in formation testing since the introduction of wireline pumpout testers (WLPT), particularly with respect to downhole fluid compositional measurements. Optical sensors and the use of spectroscopic methods have been developed to improve sample quality and minimize sampling time in downhole environments. As a laboratory technique, spectroscopy is a ubiquitous and powerful technology that has been used worldwide for decades to measure the physical and chemical properties of many materials, including petroleum, geological, and hydrological samples. However, laboratory-grade, high-resolution spectrometers are incompatible with the hostile environments encountered downhole, at wellheads, and on pipelines. Only limited resolution techniques are available for the rugged conditions of the oil field. This paper introduces a new optical technology that can provide high-resolution, laboratory-quality analyses in harsh oilfield environments.
A new technology for optical sensing, multivariate optical computing (MOC), has been developed and is a non-spectroscopic technique. This new sensing method uses an integrated computation element (ICE) to combine the power and accuracy of high-resolution, laboratory-quality spectrometers with the ruggedness and simplicity of photometers. Many modern sensors typically merge the sensor with the electronics on an integrated computing chip to perform complex computations, resulting in an elegant yet simplistic design. Now, optical sensing using ICE features an analogue optical computation device to provide a direct, simple, and powerful mathematical computation on the optical information, completely within the optical domain. Because the entire optical range of interest is used without dispersing the light spectrum, the measurements are obtained instantly and rival laboratory-quality results.
A proof of concept MOC with ICE has been demonstrated, logging more than 7,000 hours, in nearly continuous use for 14 months. Oils with gravities ranging from 14 to 65°API have been measured in downhole environments that range from 3,000 to 20,000 psi, and from 150 to 350°F. Hydrocarbon composition measurements, including saturates, aromatics, resins, asphaltenes, methane, and ethane, have been demonstrated using the MOC configuration. As compositional calculations therein, GOR and density are validated to within 14 scf/bbl and 1%, respectively. The paper discusses the details of the new ICE-based sensor and describes its adaptations to downhole applications.