Taura, Usman (Sultan Qaboos University) | Mahzari, Pedram (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Sohrabi, Mehran (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Al-Wahaibi, Yahya (Sultan Qaboos University)
In heavy oil displacement by gas, chemical, or water injection, severe instability can occur due to adverse mobility ratio, gravity or compositional effects. However, most analytical methods for estimation of relative permeability such as JBN, assume a stable front in the displacement. This implies that such methods cannot be applied to estimate relative permeability when the displacement is severely unstable.
A common approach for estimation of relative permeability in displacement with instability involves the history matching of a 2D or 3D high resolution, fine scale models of the displacement. However, this is also impractical due to associated high computational cost.
This work describes a fast methodology for the estimation of relative permeability functions in displacement with instability and compositional effect using multi coarse-scale models. It involves the history matching of a set of coarse grid models of the unstable displacement and correlating the parameter a relative permeability function (L.E.T) in order to estimate the relative permeability of the corresponding high-resolution model. By this approach, an attempt was made to resolve the fine-scale information without direct solution of the global fine-scale problem. Hence, an unstable displacement can be modelled using a coarse grid model which has a relatively lower computational cost.
The results showed that the approach is three times faster, and required less than half the memory of a conventional method.
During smart water injection into carbonates, wettability alteration is subjected to be the main mechanism contributing to incremental oil recovery. Apart from the smart water composition, level of dilution, and the underlying mechanisms, "injection scheme" is of a great importance when developing a field scale flooding project. The pivotal target of this paper is to evaluate the efficiency of smart water injection by deploying tertiary smart water "shock slug" injection within the periods of water flooding.
At the first stage, genuine reservoir brine was 10 times diluted. Ion Chromatography analysis was utilized to optimize the composition by adding 2.65 g/ml of MgSO4.7H2O. Core samples were initially flooded by the original high salinity water to reach the residual oil saturation. Smart water shock slugs were chosen in various volumes including, .75, 1, 1.5, and 2 PV. Subsequently, smart water was injected for the selected shock slug sizes. At this stage the procedure was stopped for 12 hours in order to let the smart water interact with rock sample. Afterward the process was followed by the high salinity water injection. To have a comprehensive perspective of the procedure, production data was recorded at all stages of the injection. Also, the contact angle was measured under standard condition by generating a sessile drop of oil on the carbonate surface submerged in the brine environment. The pH of the injection fluids was also measured during contact angle and core flood tests. X-Ray Diffraction inspection was utilized to analyze the mineralogy of the core samples.
Evaluating the results of the contact angle measurements, it was obtained that smart water was capable of altering the wettability towards more water wet. pH of smart water was increased after it was kept in contact with the oil-aged rock for two weeks. Core flooding results indicated that the tertiary injection of the smart water as shock slug leads to a considerable amount of incremental oil recovery at tertiary mode and changes the wettability towards more water wet. This is mainly due to the effective ionic exchange which leads to the favorable wettability alteration during smart water injection.
This study showed that smaller sizes of smart water shock slug can increase the incremental recovery as effective as larger sizes of smart water shock slug in analogues situation. Hence, the asserted method can be a good alternative for conventional low salinity water flooding due to being less time-consuming and cost-effective.
Crude oil biodegradation by bacterial strains isolated from oil contaminated soil samples, Oman, were performed and its potential applications in crude oil waste management were analyzed. Accidental and occasional crude oil spills, treatment of produced water containing hydrocarbons and oil, and waste management are a major concern for petroleum industries. Various techniques such as, chemical, physical, biological and thermal treatments, are reported for treating spills and wastes on-site. We analyzed crude oil biodegradation by selected bacterial isolates from Oman, under reservoir conditions. Four potential bacterial isolates were selected, characterized by MALDI-Biotyper, and studied for crude oil biodegradation at 40 °C. The isolates were studied morphologically and by scanning electron microscope (SEM), and any changes in surface tension (biosurfactant production), during growth on crude oil as the only carbon source. Crude oil characteristics before and after biodegradation were analyzed by Gas chromatography-Mass specrtrometry (GC-MS). The bacterial strains were identified as
Al-Ghailani, Taher (Sultan Qaboos University) | Al-Wahaibi, Yahya M. (Sultan Qaboos University) | Joshi, Sanket J. (Sultan Qaboos University) | Al-Bahry, Saif N. (Sultan Qaboos University) | Elshafie, Abdulkadir E. (Sultan Qaboos University) | Al-Bemani, Ali S. (Sultan Qaboos University)
In present paper we ereport the evaluation and the application of Alkaline-Biosurfactant-Biopolymer (ABsBp) applications for enhancing oil recovery. Generally Alkaline-Surfactant-Polymer (ASP) studies have been carried out using chemical surfactants and polymers. This experimental investigation was performed to evaluate the possibility of using a biosurfactant and a biopolymer with sodium carbonate as an alkali for ASP flooding for the oil field. The candidate example reservoir was selected having favorable properties such as high permeability (500-1000 mD), low oil viscosity (20-25 cp), favorable total acid number (0.1 mg KOH/g oil) and high residual saturation (>20%). The current study was done to design an optimum composition of Alkali/Biosurfactant/Biopolymer (AbSbP) slug and apply it for enhancing oil recovery in both native reservoir cores and Berea sandstone core plugs. The interfacial tension (IFT) between various solutions containing alkali, biosurfactant and biopolymer was measured. Interfacial tension values in the range of 0.02-0.1mN/m were achieved at low biosurfactant and alkali concentrations. The interaction of the biopolymer with the brine, biosurfactant and alkali was investigated in terms of their effect on its viscosity at the reservoir temperature of 50°C. An AbSbP slug containing 1.1 wt.% sodium carbonate, 20 v/v% biosurfactant broth and 20 v/v% biopolymer broth was recommended for the final core flooding experiment. Core flooding experiments were conducted using reservoir cores and Berea cores by injecting the formulated AbS and AbSbP slugs after brine flooding. Maximum additional oil recovery obtained was 14% and 32% of oil initially in place (OIIP) from the reservoir cores and Berea cores respectively. Such difference in additional recovery was mainly due to the vast difference in the mineralogical composition of two rock types. This is the first report of application of Alkali-Biosurfactant-Biopolymer from Oman, showing additional oil from both native cores (from the Omani oil field) and Berea sandstone cores.
The selection of the right polymer chemistry in chemical enhanced oil recovery operations is key for a successful field implementation. Operators require guarantees on polymer robustness and efficiency in order to optimize their polymer flooding processes, especially in the current context of low oil price. We evaluated different thermo-responsive polymers dedicated to Oman fields conditions in this perspective.
Several thermo-responsive polymers were considered in this study, the properties and performances of which were assessed. The purpose was to make sure that gain in dosage brought by these structured polymers is not detrimental to polymer stability and injectivity. Consequently, polymers were characterized in terms of rheological properties, thermal stability and propagation through porous media.
Thermo-responsive polymers are characterized by a LCST (Lower Critical Solution Temperature). They behave like regular polymers below this specific temperature and like associative polymers above it. The LCST varies with several parameters, including thermo-responsive moieties composition, content and molar mass, as well as brine salinity. The viscosifying properties and overall performances of such polymers are subsequently strongly driven by field conditions. Several thermo-responsive polymers were thus designed to fit model field conditions representing Oman oil fields. Rheological properties were firstly evaluated in stationary and dynamic modes, what permitted to emphasize the unique behavior of such polymers and the gain in dosage they can bring. Core flooding tests were then performed to assess polymer injectivity in porous medium. Interestingly, thermo-responsive polymers can display very high resistance factor compared to regular ones while maintaining good transport properties. The polymer retention in the core remained low. Core flood tests also gave an idea of this chemistry limitations for an use in Oman oil fields. Polymers thermal stability was determined in several conditions, fully anaerobic or in presence of O2 and H2S. The efficiency of two protective packages against H2S induced degradation was evaluated. The results after one year aging highlight the importance to avoid oxygen ingress in the system in presence of H2S. However, it is still possible to keep an acceptable level of viscosity by fine-tuning protective additives.
This study demonstrates the applicability and limitations of thermo-responsive polymers, especially in conditions that mimic Oman oil fields. These new thermo-responsive polymers are promising candidates to keep CEOR economically viable in tough conditions.
Al-Moqbali, Walaa (Sultan Qaboos University) | Joshi, Sanket J. (Sultan Qaboos University) | Al-Bahry, Saif N. (Sultan Qaboos University) | Al-Wahaibi, Yahya M. (Sultan Qaboos University) | Elshafie, Abdulkadir E. (Sultan Qaboos University) | Al-Bemani, Ali S. (Sultan Qaboos University) | Al-Hashmi, Abdulaziz (Sultan Qaboos University) | Soundra Pandian, Sathish Babu (Sultan Qaboos University)
In present study the biodegradation of partially hydrolyzed polyacrylamide (HPAM) by bacterial strains isolated from Omani oil fields was analyzed. HPAMs are extensively used in oil fields for enhanced oil recovery operations. The produced water after polymer flooding poses grave ecological problems, such as it could raise the difficulty of oil–water separation, producing toxic acrylamide that degrades naturally, which threatens the local environment. Biodegradation of HPAM by microbes may be an efficient way to solve those problems. Microbial biodegradation is considered an environmentally friendly safe technique. The isolation of microbes that are able to degrade HPAM from the oil field produced water was investigated in this study. The bacterial isolates were identified by MALDI-Biotyper and the biodegradation of HPAM was analyzed by LC-MS and reduction in viscosity by rheometer. Two HPAM degrading bacterial strains
Hatmi, Khalid Al (Petroleum Development Oman LLC) | Mashrafi, As'ad Al (Petroleum Development Oman LLC) | Balushi, Sa'Ud Al (Petroleum Development Oman LLC) | Al-Kalbani, Haitham (Petroleum Development Oman LLC) | Shaikh, Mohammed (Petroleum Development Oman LLC) | Vakili-Nezhaad, G. Reza (Sultan Qaboos University)
Rotating equipments reliability and performance have evolved in the recent decays. Manufactures continue to produce more sophisticated machines. Those equipments form a central part of any oil and gas plant. Compressors in particular considered being a major investment for any company. For any operator, keeping the compressors performance and reliability is a very major task which requires an intense OPEX spending in some cases.
This study was conducted to focus on the common issues which are related to centrifugal compressors in Oil and Gas Industries with the aim to increase the reliability and performance of this type of compressors and to form a kickoff for compressors low performance root cause analysis. Also, it will serve as a quick reference for engineers and operators to troubleshoot and optimize compression system.
The common compressors issues identification and short listing of this study was not limited to literature review instead a detailed analysis of an existing centrifugal compressor system was carried out and common issues were reported. These issues were shortlisted to focus only on the process related aspects which are liquid carry over, surge, improper system configuration, variation on inlet gas properties and pressure impacts on the performance.
An existing compression system has been selected to study the effects of the listed issues. The performance and reliability of these compressors were checked and monitored for the last three years.
To meet the objective of this study, a detailed analysis was conducted to solve these issues and optimizing the system. The study includes theoretical analysis and field troubleshooting and trials). Theoretical aspects of the work with regard to the compressor efficiency, power consumption as well as other important issues are examined based on thermodynamic analysis of the systems.
The theoretical analysis concluded that the reliability and performance of the compressor system can be increased through a number of recommendations including optimization of the suction and discharge pressure, continuous process monitoring, enhancing inter stage scrubbers’ efficiency and maintaining the gas molecular weight through compressors stages. In addition, some recommendations are given which are applicable during the design stage such as recycle line location, drain system design, seal system design and scrubbers internals accessibility. The recommendations of the theoretical analysis are under long term field trials to ensure their applicability and sustainability. The results from this study are projected to be generalized for similar type of compression system in the industry. This paper will be of interest to anyone who designs or operates multistage compression systems.
Ground penetrating radar (GPR) is widely used for shallow (cms to tens of meters) subsurface imaging. Full-waveform inversion (FWI) of GPR data has enabled researchers to increase the subsurface image resolution. The FWI technique has been applied primarily to off-ground GPR and crosshole GPR data, due to complexity of surface-based on-ground data. A major difficulty with common-offset surface GPR data is the source wavelet estimation, particularly due to presence of the air wave, ground wave and noise. Existing deconvolution methods for estimation of the source wavelet require preliminary knowledge of the subsurface. Sparse blind deconvolution (SBD) methods permit estimation of the source wavelet without an initial synthetic model of soil structure. We investigate the performance of an SBD method to estimate the source wavelet of common-offset GPR data The effects of including/excluding the air/ground wave are studied on both synthetic and simple field test data involving a single buried pipe. For the 2D synthetic model, SBD extracts the wavelets. For the real field data, the estimated wavelets are compared to those derived from the deconvolution method. Ongoing research will examine the relative quality of FWI inversion results based on wavelets estimated with SBD..
Presentation Date: Monday, September 25, 2017
Start Time: 4:20 PM
Presentation Type: ORAL
ABSTRACT: Induced stresses are one of the main factors affecting wellbore instability and associated problems in drilling operations. These stresses are significantly impacted by pore pressure variation and thermal stresses in the fields. Heat and fluid transfer capability of rock and thermal expansion coefficient are important parameters in the study of stresses using a thermo-poroelastic model. In this study, the field equations governing the problem have been derived based on the thermo-poroelastic theory and solved analytically. Afterward, the couple of 50 mm synthetics sand-cement samples are applied in laboratory experiments. The in situ stresses and wellbore pressure are applied on the sample in a true triaxial stress cell (TTSC). In the laboratory tests, the temperatures are controlled and cooled oil is injected into the sample. The strains are measured and calculated based on experiment and model. In the next step, a genetic algorithm has been applied to solve an inverse problem and get a match between experimental data and the modeling results. Ultimately, the important properties for the interactions of fluid and rock can be estimated. With this approach, the required thermal and flow parameters are estimated with good accuracy without using time consuming and costly tests.
Wellbore stability has an important role during drilling. The formations around wellbore experience new stress conditions due to the removal of drilled rocks (Fjaer, Horsrud et al. 2008, Al-Ajmi and Zimmerman 2009). Any point below ground carries different stresses, namely vertical stress due to the overburden or weight of overlaying formations, horizontal stresses from tectonic movements and pore pressures (Amadei 1984).
The assumed rock formation behavior is a significant factor in modeling the stresses around a borehole. In this regard, Mclean and Addis (Mclean and Addis 1990) pointed out that a poro-elasto-plastic model can give more realistic results than a linear elastic model. In addition, Bradford and Cook (1994) suggested using an elasto-plastic model for stress modeling and they have applied their recommendation in wellbore stability analysis for vertical well with isotropic in situ stresses. Furthermore, Chemo-poro-elastic model is used to determine the stresses around the wellbore in shale formations(Ma, Chen et al.).
This study focuses on the evaluation and diagnosing of the potential severity of petroleum reservoirs for establishment of phase traps. In this area, very few diagnostic methodologies have been presented in the literature. Unfortunately, there is no universal agreement on the key influential factors in a phase-trapping phenomenon because each of the correlations was established on the basis of different sets of reservoir parameters (e.g., k, ?, Swi, σ) by use of the results of a number of aqueous-phase-trap tests over a limited range of rock and fluid properties. In the present work, an accurate technique is presented on the basis of the infiltration theory for prediction of the potential severity of phase-trapping damage. The fluid-saturation distribution around a well is analytically derived by linearizing and solving the governing partial-differential equation (PDE). Then, the calculated saturation profile in the vicinity of the wellbore is used to develop a new analytical diagnostic index, which is called a phase-trapping index (PTI). Knowing the fact that the saturation of the affected zone may be reduced to the irreducible rather than the initial value because of the capillary mechanics of the formation, interpretation guidelines are proposed to identify the regions that are susceptible to intense, serious, medium, and weak damage.
Compared with other correlations, PTI offers several advantages such as generality, being founded on theory, and taking into account most of the key influential parameters. An example of a synthetic tight gas reservoir is presented to clearly demonstrate how the new technique can be applied.