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.
A live oil sample was subjected to a solid detection system (SDS) to measure asphaltene onset point (AOP) at 3850 psi, and asphaltene content of 1.3%. A high-resolution digital camera was used to measure asphaltene particle size distribution. The result showed that asphaltene particles were not uniform in size, but has a normal distribution of 100-120 µm. Asphaltene reversibility to dissolved back into the oil with increasing pressure was only 35% of the original deposition. Two core samples were examined for formation damage due to asphaltene deposition. A Low permeability core showed significant permeability reduction exceeding 50% of its baseline permeability, and the higher permeability core showed less permeability decline, even with the same asphaltene precipitation.
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.
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)
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.
Anti-agglomerant (AA) has emerged over the last decade as a new technology foroffshore hydrate control thanks to its unique hydrate control mechanism andlower application dosage. However, field operational issues, such asfluids
separation, water quality and corrosivity in the presence of protic solvents,have prevented the growth of this technology industry-wide as a reliable andefficient hydrate control alternative to methanol and monoethyleneglycol.
In this paper, we are reporting a new AA product formulated with anewly-developed proprietary chemistry. The product has been tested under fieldimplementation conditions in hydrate control performance (dose rate, salinity,water cuts and
types of hydrocarbon), fluids emulsions and water quality, and corrosiontendency (on both SS304 and SS316). A new method using gas chromatography withflame ionization detector (GC/FID) and gas chromatography withNitrogen/Phosphorus Sensitive Detection (GC/PND) has been developed to quantifyAA partitioning and distribution in the fluids (hydrocarbon and water phases).The relationship between fluids quality and AA actives partitioning in bothaqueous
and hydrocarbon phases has also been established to elucidate why the new AAprovides much improved fluids separation and water quality. It also confirmsthe observations made through bottle shaking testing.
Under severe lab testing conditions where quaternary ammonium chemistries showcorrosion and pitting on both SS340L and SS316L, the new AA product offerssatisfying material compatibility, although it has the same solvent packageas
existing commercial AAs. Comparison of toxicological properties with differentAA chemistries has also been conducted.
Under the CEFAS testing protocol, the new AA chemistry presents improvedenvironmental properties over conventional AA chemistries.
Key words: hydrate control; low dosage hydrate inhibitor (LDHI),anti-agglomerant (AA), emulsion tendency, water quality, partitioningefficiency, pitting corrosion and ecotoxicology (EcoTox).
Precipitation of asphaltene is a serious and common challenge faced by the oil industry during production of heavy oil. Regular treatments are often required to reinstate lost productivity by removal of such deposits from tubing or within the reservoir.
Hydrocarbon-based solvents, like xylene or xylene mixtures, are the most commonly used recipes for dissolution of deposited asphaltenes. While such treatments are effective, they sometimes present problems with respect to health, safety, and environmental (HSE) characteristics (lower flash points and the presence of benzene, ethyl benzene, toluene, or xylene (BETX) components), which can limit their use. Recently, water/solvent emulsion systems that offer significant advantages compared to traditional recipes have been used. The solvents used in these emulsions have relatively higher flash points, making them a safer alternative. Further, the redeposition process is delayed because the treated surfaces are left in a water-wet condition.
This paper describes the application of such water/solvent emulsion systems used to treat asphaltene deposits from two distinct regions of the eastern hemisphere. The steps taken to optimize a recipe suitable for dissolution of the asphaltene deposits are highlighted. This is extremely important to the design of a successful treatment because the complexity of the deposits vary regionally. Higher solubility values were obtained with the emulsion system when compared to xylene. Importantly, these emulsion systems could also be designed with acid as an aqueous phase. This increases the solubility values significantly because acid-soluble inorganic minerals were also found in conjunction with asphaltene in the deposits studied. The data presented demonstrates the applicability of the emulsion system for effective removal of asphaltene deposits and recovery of lost productivity. This environmentally acceptable emulsion system can contribute significantly to profitable and sustained production of heavy oil when faced with asphaltene challenges.