A Jurassic oil field in Saudi Arabia is characterized by black oil in the crest, with heavy oil underneath and all underlain by a tar mat at the oil-water contact (OWC). The viscosities in the black oil section of the column are similar throughout the field and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large, continuous increase in asphaltene content with increasing depth extending to the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. A simple new formalism, the Flory-Huggins-Zuo (FHZ) Equation of State (EoS) incorporating the Yen-Mullins model of asphaltene nanoscience, is shown to account for the asphaltene content variation in the mobile heavy oil section. Detailed analysis of the tar mat shows significant nonmonotonic content of asphaltenes with depth, differing from that of the heavy oil. While the general concept of asphaltene gravitational accumulation to form the tar mat does apply, other complexities preclude simple monotonic behavior. Indeed, within small vertical distances (5 ft) the asphaltene content can decrease by 20% absolute with depth. These complexities likely involve a phase transition when the asphaltene concentration exceeds 35%. Traditional thermodynamic models of heavy oils and asphaltene gradients are known to fail dramatically. Many have ascribed this failure to some sort of chemical variation of asphaltenes with depth; the idea being that if the models fail it must be due to the asphaltenes. Our new simple formalism shows that thermodynamic modeling of heavy oil and asphaltene gradients can be successful. Our simple model demands that the asphaltenes are the same, top to bottom. The analysis of the sulfur chemistry of these asphaltenes by X-ray spectroscopy at the synchrotron at the Argonne National Laboratory shows that there is almost no variation of the sulfur through the hydrocarbon column. Sulfur is one of the most sensitive elements in asphaltenes to demark variation. Likewise, saturates, araomatics, resins and asphaltenes (SARA); measurements also support the application of this new asphaltene formalism. Consequently, the asphaltenes are very similar, and our new FHZ EoS with the Yen-Mullins formalism properly accounts for heavy oil and asphaltene gradients.
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.
Adhi gas-condensate field is located near Islamabad, Pakistan. Pakistan Petroleum Limited started fluid processing and recovery of Liquefied Petroleum Gas and Condensate around in 1990. The liquid stream was processed with no solids deposition in the past. Recently, the liquid processing circuit of the plant has experienced an increasing amount of black solid deposition, which is trapped into the liquid filters located in the plant.
To identify the root causes of the problem of these solids depositional systematic approach was applied including taking various solid, liquid and gas samples from the plant inlet and various locations inside the processing plant and analyzing them for diagnostics.
Based on the outcome of the root-cause analysis, a chemical mitigation strategy has been developed, tested and implemented, resulting in significant reduction in problems related with solid depositions in processing plant.
Adhi gas condensate field is located near Islamabad, Pakistan. The fluid in Adhi is processed in two liquefied Petroleum Gas (LPG)/Natural Gas Liquid (NGL) plants (plants I and II) and Oil Stabilization Facility (OSF). The condensate was processed without solid deposition in these plants from 1990 to 2007.
The black solid deposits started to accumulate on the process equipment and plants' filters (Figure-1)leading to a high filter change frequency and consequent production loss.
Due to the continuous increase of the severity of the problem, a full Flow Assurance (FA) review of the field was carried out in order to mitigate the solid precipitation and problem of its depositions in plant. The first phase of the FA review was to conduct a Root Cause Analysis (RCA) where the main causes were identified including fluid compositional changes, temperature and pressure changes across the system, and incompatibility of mixing well streams with different compositions were identified to be the main causes for the asphaltenes dropout.
The RCA was based on the historical plant production data, fluid sampling, analysis results and asphaltene thermodynamic modeling.
The outcomes were:
This article details the methodology followed in solving the solid deposition problem at Adhi.
As the high demand for fossil fuel pushes the frontiers of oil exploration and production into more hostile environments, issues associated with flow assurance have become increasingly important. This is especially true of paraffin wax precipitation and deposition in areas of reduced temperatures, such as the Polar Regions and in deep sea environments. In order to reduce costly remedial operations aimed at removing pipe/tubing blockages resulting from wax deposition, it is essential to predict when, where and how much paraffin wax is deposited during the working life of oilfield installations. In this study, a computer application model capable of predicting wax precipitation and deposition in oilfield installations under various conditions of flow was developed. Thus, a computational flow dynamics (CFD) program named "WD-Predictor?? using C++ language was designed and developed with mathematical models that approximate the physical behavior of wax crystallization and deposition systems such as; Property Transport Models (Energy, Momentum and Mass),Thermodynamic Equilibrium Model and Wax Deposition & Erosion Model. The mathematical models developed were discretized while numerical solutions to the discretized models were then developed using appropriate algorithms and pseudo-codes. The "WD-Predictor?? was used to estimate the Wax Appearance Temperature (WAT) of three crude samples. The results obtained were compared to an experimental results published; Exp.WAT for oil sample 1 was 87.800oF and Predicted was 89.888oF, for oil sample 2- the Exp. WAT was 114.35oF and predicted was 115.76oF and for oil sample 3, Exp. WAT was 72.950oF while Predicted was 70.620oF. Again, WD-Predictor results were compared with the experimental data extracted from Cordoba and Schall (2001). Above all, WD-Predictor output on wax deposition thickness was also compared with the enthalpy-porosity model proposed by Banki et al. (2008) and in all the WD-Predictor showed consistence in results, in line with these published experimental results. Finally, WD-Predictor was validated with a well-tested simulator PROSPERTM on pressure and temperature profiles using Beggs & Brill Correlations.
Ahn, Taewoong (Petroleum and Marine Resources Division, Korea Institute of Geoscience and Mineral Resources) | Lee, Jaehyoung (Petroleum and Marine Resources Division, Korea Institute of Geoscience and Mineral Resources) | Lee, Joo Yong (Petroleum and Marine Resources Division, Korea Institute of Geoscience and Mineral Resources) | Kim, Se Joon (Petroleum and Marine Resources Division, Korea Institute of Geoscience and Mineral Resources) | Park, Changhyup (Department of Energy and Resources Engineering, Kangwon National University)
Falser, Simon (Centre for Offshore Research and Engineering, Department of Civil & Environmental Engineering, National University of Singapore) | Loh, Matilda (Centre for Offshore Research and Engineering, Department of Civil & Environmental Engineering, National University of Singapore) | Palmer, Andrew (Centre for Offshore Research and Engineering, Department of Civil & Environmental Engineering, National University of Singapore) | Tan, Thiam Soon (Centre for Offshore Research and Engineering, Department of Civil & Environmental Engineering, National University of Singapore)
Asphaltene precipitation and deposition can occur in some heavy oil reservoirs during the primary depletion or gas-lift process, when a pressure drop from the subsurface reservoir formations to the surface treating system is rather large. These precipitated asphaltenes may be deposited onto various locations along the production system so that it can be partially or completely plugged. Therefore, it is necessary to determine the possibility and severity of asphaltene precipitation at the early stage of heavy oil production. On the other hand, a number of chemical, thermal, and mechanical methods have been developed to reduce or eliminate asphaltene precipitation and deposition. The most commonly used means is through chemical treatment by applying an asphaltene precipitation inhibitor (API), which is a specially designed and synthesized chemical compound to control or inhibit asphaltene precipitation.
In this paper, both visual and filtration methods are used to determine the onset pressures of asphaltene precipitation and redissolution of a recombined live heavy crude oil during an isothermal pressure-reduction process at different temperatures and gas-oil ratios (GORs). The experimental results show that a higher temperature can lead to a lower onset pressure of asphaltene precipitation and a less amount of precipitated asphaltenes, i.e., delayed and reduced asphaltene precipitation. This is because at a higher temperature, the solubility of the resins in the live heavy crude oil is higher, which helps to stabilize asphaltenes in the oil. It is also found that in contrast, the live heavy crude oil with a higher GOR has earlier and stronger asphaltene precipitation during the isothermal pressure-reduction process. In this case, the composition of the live heavy crude oil with a higher GOR is lighter and the solubility of asphaltenes in such a live crude oil is lower. Thus, asphaltenes become more unstable and likely to aggregate and precipitate. Finally, the filtration method is also applied to evaluate the effectivenesses of two APIs (API-A and API-B) by comparing their abilities to stabilize asphaltenes in the API-treated live heavy crude oils during the isothermal pressure-reduction process. API-A is proven to be capable of substantially lowering the onset pressure of asphaltene precipitation and the pressure-drop increase in the filtration process. Furthermore, API-B is found to be more effective to inhibit asphaltene precipitation than API-A as no noticeable pressure-drop increase during the isothermal pressure-reduction test is measured for the live heavy crude oil treated with API-B.
The precipitation and deposition of paraffin wax during production, transportation and storage of crude oil are common problems encountered by the majority of oil producers around the world. During the last decade, the Barrackpore oilfield in Trinidad has reported wax deposition on nineteen (19) of its wells. This condition has been exacerbated due to the reduction of temperature, pressures and losses of gas which have allowed wax to separate from the crude oil, precipitate and deposit in the walls of tubings, thereby reducing their diameter and restricting the flow of oil through the system. The situation represented a serious problem for Petroleum Company of Trinidad & Tobago (Petrotrin), because it caused a reduction in the production levels and significant economic losses. This study was based on the necessity to find feasible solutions to minimize this problem. The research was focused to determine if there was influence of the resin/asphaltene ratio on wax deposition under laboratory conditions, to start an understanding process of the causative factors of these depositions. In addition, the influence of two (2) different wax inhibitors were studied for comparison, since it is understood they may behave as resins peptizing the asphaltene particles and keeping them in solution. To ensure the validity of this investigation, extensive bibliographical reviews were undertaken, followed by numerous laboratory tests such as SARA analysis, Cloud Point Tests and Wax Content Tests as methods to evaluate the crude oil and its behaviour under various conditions. The results showed that wax and asphaltene content are the controlling factors in the precipitation and depositions processes respectively.
Shepherd, Andrew G. (Nederlandse Aardolie Maatschappij BV) | van Dijk, Menno (Shell Global Solutions Intl BV) | Koot, Wouter (Shell Global Solutions) | Dubey, Sheila Teresa (Shell Global Solutions) | Poteau, Sandrine (Shell) | Zabaras, George John (Shell Global Solutions) | Grutters, Mark (Shell)
This paper presents an overview of the different flow assurance issues associated with naphthenic acids. In field development projects a good understanding of naphthenic acid phase behavior is essential to avoid unplanned plant changes and deferment. Good data on naphthenic acid content and speciation is obtained by using a representative sample. Basic measurements (e.g. TAN) are not sufficient to obtain a detailed understanding of the flow assurance issues regarding a particular crude oil. Infrared spectroscopy and mass spectrometry, high and low resolution, are the preferred tools for analysis of crude oils. The target naphthenic acid species, e.g. ARN or fatty acids will dictate the best suited method selected for analysis. Geochemical analysis of crude oils has helped to highlight some common features which can be used for prediction purposes. For bound soap scale-forming crude oils, a large amount of complexed acids result in emulsions which are difficult to break. Chemical treatments are needed and these should be identified early in the project stages. For soap scale-forming crude oils chemical treatment requires in depth analysis of topsides equipment and impact on existing chemical portfolio. Surveillance of soap scale-forming crude oils is possible using readily available equipment. For soap emulsion-forming crude oils, paraffin precipitation adds to the stability of the emulsion formed. Chemical treatment and heat is required for best results. Use of stock tank sample properties can be used for predictions regarding the type of naphthenic acid issue to be expected for particular crude oil sets.
Naphthenic acids play an important role in upstream and downstream oilfield activities in many diverse areas such as exploration geochemistry and corrosion. In E&P field developments within the discipline of flow assurance, the effects of naphthenic acids in crudes and condensate systems have been specifically reported in emulsion stabilization, formation of soaps, enhanced oil recovery performance and in natural hydrate inhibition1-5. The impact of naphthenic acids on facilities design cannot be underestimated. Most issues are treated with chemical solutions, and this affects CAPEX as well as OPEX. Thus there should be robust protocols to ensure naphthenic acids are correctly identified in conjunction with the other reservoir fluid properties as early as possible. By taking these steps, costly retrofitting or plant changes and deferment can be avoided. This work will review lessons learned to better understand the properties of naphthenic acids systems and their flow assurance impact. This will include a discussion on different related case histories. It should be mentioned that the impact of naphthenic acids should be studied on a field by field basis with a fit for purpose approach.