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Results
Artificial Intelligence Recovery Modeling of <5 API Unconventional Next-Generation Heavy Oil Using CHNSO Technology
Adel, N. Abu (Australian College of Kuwait) | Abdullah, F.. (Australian College of Kuwait) | Al-Kanderi, H.. (Australian College of Kuwait) | Tesiari, E.. (Australian College of Kuwait) | Ghafoori, S.. (Australian College of Kuwait) | Alkazimi, M. A. (Kuwait Oil Company) | Al-Bazzaz, W. H. (Kuwait Institute For Scientific Research)
Abstract Extreme heavy oil <5 °API is considered a type of unconventional tight oil, which will require a challenging petroleum production system for future new-generation extreme heavy oil or bitumen carbonate reserves. This oil is abundant in great amounts around the globe, yet is extremely difficult to produce due to its solid-like physical state locked deep underground. The world strategy eventually will shift focus to this type of oil since conventional and other less-quantitative-difficult reservoirs are continuously depleting. The interest of this study is directed towards a specific type of unconventional oil, which is available in tight carbonate reservoirs. Extreme heavy oil <5 °API exists in large quantities in Kuwaiti fields. This study presents a novel heavy oil classification especially for <5 °API crude oil types as well as their potential recoveries. All recoveries considered for this study are bench-scale laboratory physical experiments with toluene, de-ionized water and water-aided surfactants augmented with applied field thermal 25 °C, 135 °C, 225 °C and 315 °C heat treatments. The main objective for this research is to model five signature atoms available in almost all heavy crude oils: carbon, hydrogen, nitrogen, sulfur, and oxygen (CHNSO). These CHNSO fingerprints determine qualitatively and quantitatively the potential amount and quality of future extreme heavy crude oil recovery. An Artificial Intelligence (A.I.) neural network algorithm is developed for all possible conjecture atoms. A Multiple Layer Forward Feed (MLFF) learning system is designed, trained and applied for developing the A.I. neural network. Forty-one recovery models are manifested in this study, clustered in possible atom conjecture operational base-function domains, which are unary (one atom), binary (two atom), ternary (three atom), quaternary (four atom) and quinary (five atom) approach models. The main technological motivation for CHNSO research is finding the optimized conventional EOR recovery efficiency factor that will extract <5 °API oil. The model predicts the recovery potential factor in a classic, optimum and conventional economic scenario, considering the unconventional environmental impact, crude oil subsurface-mobility issues and technology limitations used as current economic challenges. The general summary of results suggest that CHNSO models are useful in better understanding and better predicting <5 °API oil recoveries. The three-atom nitrogen-sulfur-oxygen (NSO) ternary conjecture model has a significant impact regarding heavy crude oils, maximizing recovery in general, and extreme heavy oil potential recovery in particular, in regards to the difficult mobility of this type of crude oil.
- Europe (0.46)
- Asia > Middle East > Kuwait (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.50)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract An experience of ESP issues troubleshooting to overcome high corrosion media of GSA wells is presented. Likewise, actions taken to extend run life of pumps are explained. GSA is the unique company in Algeria adopted ESP system including all services, there was no chance to share experience with other entities in Country. Thus, it became necessary to try all available approaches during a journey of 10 years to mitigate ESP failures and eventually production downtime. To overcome high salinity of >320 g/l, several actions were introduced in either ways, ESP equipment or well completion. Simple motors and protectors changed to tandem to prevent water penetration inside motor. Power cable was changed from Galvanized to Monel Armor for high corrosiveness. Completion wise, one or double 1/2" water dilution lines were adopted, run along tubing, connected to tail pipe which run to perforations. Modification in completion metallurgy took place also, when Carbon steel replaced by Super 13Cr instead. Supplementary actions taken at surface, pressure switch was connected with VSD to smoothly shutdown ESP for unforeseen SCSSV closures. The adopted actions yielded considerable positive results. ESP failures originated from water penetration inside motor was reduced to 20%. Whereas, salt deposition blocs were almost prevented and resulted decrement in bullheading and coiled tubing interventions by 85%, except for some wells when salt bloc build-up is occasionally quicker and more important than water dilution rate. Running 1/2" injection line along with tail pipe led to less ESP shutdowns frequency. Changing the power cable type gave roughly good results as well. Once running Monel Armor, number of power cable failure related decreased and consequently contributed in reduction of whole failures. Saying that because power cable failure related represented 70% of ESP failures in 2015. Considering Super 13Cr instead of Carbon steel tubing gave positive indications and reduced sharply tubing integrity failure related. The problem still exists, however, with very low frequency. For surface equipment, all unforeseen SCSSV closure, actuated from control panel is always accompanied with gradual decrement of frequency and consequently smoother ESP shutdown. As our organisation is the truly company that uses ESP with a proper sense in Algeria, This paper presents some best practices to be considered for other companies and ESP contractors based in the country or abroad that intend to both install ESP system in very high salinity and corrosive fields and adopt lease model for downhole Equipment.
Abstract Corrosion of oilfield equipment and processing facilities is a common occurrence that can pose a serious threat to the integrity of the facilities. When failures occur, the leaking substances can be very dangerous to lives and be very harmful to the environment for a long time. Direct total costs due to corrosion, its preventive measures, repairs and litigations are in the billions of dollars each year. Identifying the type of corrosion is the first step in the analysis and prevention of corrosion-related failures. Visual inspection of the pit morphology can give insights into the type of corrosion that is occurring. This paper describes how to identify the corrosion mechanism based on the pit orphologies. Descriptions and diagrams of pit morphology of each type of corrosion along with actual pictures of the typical corrosion or failures are included.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
The pdf file of this paper is in Russian. Development of technologies and methods enhancing oil recovery with thermal, physical, chemical methods and its combinations being widespread among them is crucial challenge for developing stranded and unconventional hydrocarbon reservoirs. The high pressure air injection in productive stratum is resulting in occurrence of complex thermo-chemical and thermo-dynamical reactions. Application efficiency of the injection should be estimated by preliminarily defining of hydrocarbon chemical conversion mechanism while interacting with air's oxygen and experimental studying of thermal air impact on oilcontaining rock in reservoir conditions. To address these challenges VNIIneft AO has developed a comprehensive approach to assess the possibility of this technology utilization for the particular field conditions. The cornerstone of developed technique consists in subsequent carrying out of complex experimental researches (physical modeling of in-situ combustion process) with high pressure differential scanning calorimeter (DSC1), thermochemical reactor and combustion tube to obtain data required for mathematical modeling of in-situ oxidizing/combustion on particular field. Complex approach to study a mechanism of in-situ combustion occurrence is based on its dividing into stages differing physical and chemical processes with specific reactions of chemical conversion for hydrocarbon and non-hydrocarbon oil components and on definition of principal parameters for the oil displacement modeling while thermal impacting with an oxygen in the air. While interaction with air's oxygen in the low-temperature area the largest amount of different reactions is occurring in accordance with chemical conversion mechanism of hydrocarbon groups. Thus, an area of low temperature oxidizing commonly being not taken into account in modeling of the thermal method presented has a major role during in-situ combustion. The studying of the reactions specified for the areas of low temperature oxidizing and building of the chemical conversion model fully taking into account the oxidizing process of reservoir oil with oxygen in the air are the essential advantages of the developed technique.
Abstract This paper presents some of the challenges and learnings associated with the application of preservation chemicals in a network of subsea Umbilicals, Risers, and Flowlines (URF) for a large-scale Liquefied Natural Gas (LNG) project in Australia. An overview of key considerations for chemical treat of water to meet the specifications necessary for long-term preservation of carbon steel and Stainless Steel (SS) cladded flowlines is also provided. Furthermore, the steps involved in formulating and qualifying a multi-purpose product to meet the requirements of the project are discussed. In development of offshore gas fields the construction and commissioning of downstream infrastructure often extend beyond the time required to complete the installation of piping systems used in transporting gas and fluids to the processing centre. During the pre-commissioning phase, cleaning and pressure testing of production and service lines must be finalized to verify the structural integrity of the asset. The process is referred to as hydrostatic testing (or Hydrotesting) as water is typically used as the pipeline filling medium. The presence of water within the lines, following the completion of Hydrotesting procedures, can pose a serious corrosion risk due to the potential for growth of bacteria, deposition of sediments, and in certain systems the presence of dissolved oxygen in water. For these reasons, the use of preservation chemicals during Hydrotesting and subsequent preservation of pipework is critical to maintaining the integrity of the system. Preservation treatments typically consist of an active component for controlling Microbiologically Induced Corrosion (MIC), an oxygen scavenger to remove dissolved oxygen, and in some cases a corrosion inhibitor to supplement the treatment program. The case history describes the best practices adopted in preservation of the above-mentioned URF system, located in an ecologically sensitive environment. In this project, the materials of construction of the flowlines demanded stringent specifications on the quality and treatment requirements for the Hydrotest water, to make it suitable for use in SS cladded flowlines. This condition, combined with the requirement for an environmentally-friendly chemical, drove the development of a ‘green’ preservation product cocktail with good corrosion inhibition performance and oxygen removal efficiency. Onsite sampling and chemical analysis procedures were also developed to ensure adequate and consistent application of the chemical during pipeline filling operations. The analysis allowed for accurate measurements of the product active components which, in turn, enabled the chemical treatment rate to be maintained within a narrow range. It is anticipated that the newly developed product will be used in similar projects operating within environmentally sensitive locations where the use of a single, multi-functional chemical cocktail with a superior environmental profile is required.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Summary The lack of an accurate reaction model for petroleum-oxidation rates is a serious hindrance to the simulation of oil-recovery processes that involve air injection. However, the chemical literature on hydrocarbon oxidation contains many examples of possible reaction mechanisms that could serve as guides. These mechanisms were screened to identify generally accepted reaction paths that could help reveal how oxidation occurs in petroleum reservoirs. It was found that there are at least eight groups of fundamental reactions that can seriously affect oxidation rates of crude oils or their pyrolysis products. These eight reactions are as follows: two that lead to hydroperoxide formation; “branching” by hydroperoxides; two reactions governing the negative temperature coefficient (NTC) region; oxidation inhibition; at least one rate-controlling reaction at very high temperatures; and the combustion of coke that is produced by pyrolysis. Each of these groups exerts an influence within a separate, identifiable range of conditions. These reactions, and the conditions under which they become important, are outlined in this paper. Various oxidation behaviors that were reported for both light and heavy crude oils were then compared and aligned with the eight identified reactions. The result was a framework for selecting pseudoreactions that can facilitate the prediction of the oxidation kinetics under a wide range of oilfield conditions. Some of these pseudoreactions involve the direct representation of free radicals or other chemical intermediates, which is a departure from conventional practice for in-situ-combustion simulation. The new reaction framework is expected to serve as a reliable guide to the construction of predictive reaction models and, consequently, improved simulation of both in-situ-combustion and high-pressure-air-injection (HPAI) processes.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.70)
- Geology > Mineral (0.67)
- Geology > Geological Subdiscipline (0.57)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.52)
Summary The presence of oxygen and carbon dioxide in the injection and production streams of any high-pressure-air-injection (HPAI) project or the high oxygen partial pressures associated with enriched-air-/oxygen-injection projects may create serious safety concerns such as the potential for explosion or corrosion. Compilation of field problems and reported solutions from such projects indicate that no insurmountable problems exist in the implementation of HPAI projects. Generally, the operators have implemented safe operations successfully when injecting at pressures as high as 6,000 psi. The long-term successes of the HPAI projects in the Williston basin, which were initiated in 1978 by Koch Industries and continue to be operated today by Continental Resources, have confirmed that HPAI is a viable and safe process for recovering light oils. A number of oilfield oxygen-injection projects have also been undertaken since the early 1980s, when Greenwich Oil operated the first oxygen-injection project at Forest Hills, Texas. In Canada during the 1980s, oxygen was injected by BP/AOSTRA at Marguerite Lake, by Dome Petroleum at Lindberg, by Husky Energy at Golden Lake, by Mobil Oil at Fosterton, and by Gulf Canada at Pelican. In the US, oxygen-injection pilots were operated by Arco in the Holt Sand Unit (HSU), Texas, and more recently by NiMin Energy at Pleito Creek, California. With increased oxygen partial pressure, there is a greater chance of safety or corrosion problems. In fact, the high oxygen content associated with the HSU project in west Texas caused a severe energy release that resulted in test termination. The reported data on this field are scarce, and the nature of the energy release has not been discussed in detail. This paper will first review the operational aspects of some key air-injection field tests. Then, some important details on the HSU oxygen-injection pilot test will be discussed as a case study. The reasons behind the energy release in the HSU project will be discussed by use of the surveillance data, as well as combustion-tube-test and numerical-modeling results. Finally, best practices for future operation of HPAI tests will be reviewed. This paper is intended to provide a better understanding of the safety aspects of air/oxygen handling and proper practices in such operations.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.46)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Mineral (0.46)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.41)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
- North America > United States > Texas > East Texas Salt Basin > Forest Hill Field > Harris Sand Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Buffalo Field (0.99)
- North America > United States > South Dakota > Williston Basin (0.99)
- (6 more...)
Abstract Microbial enhanced oil recovery (MEOR) is one of the enhanced oil recovery (EOR) techniques that is applied to oil reservoirs after primary and secondary recovery techniques to increase oil production. The successful implementation of MEOR involves an interdisciplinary approach. This paper has focused on one of such approaches which is the bioengineering aspect of MEOR that is concerned with the quantitative description of microbial growth and yield factors. Early MEOR works have focussed on the use of external carbon sources i.e. carbohydrate nutrients to produce metabolites useful for oil recovery, using the petroleum hydrocarbons present in the reservoir as the carbon source for microorganisms can be essential in microbial enhanced oil recovery as this addresses some logistic problems encountered in adverse environment. The metabolites which are useful in MEOR techniques for oil recovery can be produced by growing the microorganisms on petroleum hydrocarbons. The microbial degradation of n-alkanes and some readily biodegradable substrate has been studied. A simple respirometric method has been developed to assess the biodegradability of these compounds. Initial experiments have been performed in small-scale laboratory bioreactors to determine hydrocarbon degradation rates through oxygen consumption data (under aerobic conditions) collected over a period of time. Analysis of initial kinetic parameters has shown that estimates of hydrocarbon biodegradation based on respirometry is very reproducible with some consistency in the data generated. It has been shown from calculated microbial growth rates that petroleum hydrocarbons can be utilized under aerobic conditions at reasonably rates. The biodegradation of petroleum hydrocarbons using nitrate as electron under anoxic conditions has also been studied.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
Abstract The Accelerating Rate Calorimeter (ARC) is unique for its versatility of operation and application - reliability, validity, and accuracy of results - due to very high adiabaticity. Accelerating Rate Calorimetry is one of the screening tests employed to determine the suitability of a reservoir for air- injection Enhanced Oil Recovery. The ARC is well suited for investigating the reaction mechanisms in the Low-Temperature Range, Negative Temperature Gradient Region, and High-Temperature Range. The ARC provides full time-temperature, time-pressure, and self-heat rate-inverse absolute temperature profiles. An experimental and simulation study was carried out to expand knowledge and interpretation of the data derived from high pressure closed ARC tests. Athabasca bitumen was used for the experimental study in a closed ARC at an initial pressure of 13.8 MPag (2,000 psig) to identify the nature of the oxidation reactions occurring over the different temperature ranges. The simulation component of the study focused on the development of a numerical model that captured the elements of the ARC test. The model incorporated solubility of oxygen and diffusion to control the transfer of oxygen in the liquid oil phase. Mass transfer was found to play an important role at low temperatures up to the temperature where chemical interaction starts to control the distribution of oxygen within the liquid bitumen. Likewise, vaporization of oil and generation of vapor by cracking reactions are also believed to play an important role in air injection processes. Therefore, a vapor phase combustion reaction was integrated into the traditional Belgrave s kinetic model. This modified model predicted the combustion of vaporized oil in the gas phase by flammable limits and rate of diffusion of the vaporized component in the gas phase to become flammable. The results of this study indicated that with the addition of mass transfer to the traditional kinetic model, it was possible to predict the negative temperature gradient region. The result showed solubility and diffusion of oxygen played an important role up to a temperature of 125°C where chemical reactions started to control the distribution of oxygen within the liquid bitumen. The results also showed that vapor phase combustion created a temperature gradient between the gas and bitumen phases when vaporized components became flammable. This showed that the ARC could be an effective tool for understanding liquid and vapor phase reaction and their relative importance in different temperature regimes.
- North America > United States (1.00)
- North America > Canada > Alberta (0.30)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract Membrane nitrogen with up to 5 vol% O2 is widely used as blanket gas in the petroleum industry, including as blanket gas on rich and lean MEG tanks. The presence of oxygen, even in low concentrations raises questions with regard to potential corrosion damage in the carbon steel injection line as well as consumption of the dissolved oxygen and residual levels upon entering the pipeline. These aspects constitute the scope of this work. A series of experiments were carried out with carbon steel specimens exposed to environments similar to service conditions encountered in MEG injection lines, including temperatures between 5 and 65 °C and various levels of alkalinity/acidity. The corrosion processes were monitored by electrochemical measurements. These allowed the empirical determination of a number of parameters governing the corrosion and oxygen consumption reactions. Based on the experimental findings and literature data, a comprehensive finite element model was developed and used for tracking the corrosion rate along an injection line of Lean MEG in the presence of dissolved oxygen under acidic, near-neutral and alkaline conditions. Consumption of dissolved oxygen along the injection line was accounted for via the bulk oxygenation of ferrous iron released during the corrosion process. The experimental results revealed that the contribution of electrochemical oxygen reduction to the corrosion rates is minute; the oxygen is rather consumed in reaction with ferrous ions in the bulk. The model reproduced the measured corrosion rates well and made it possible to study the consumption of dissolved oxygen as a function of acidity/alkalinity, temperature and residence time. The results showed, for example, that the dissolved oxygen may not get completely depleted in the injection line at high flow rates. The results presented here, as well as the approach used by the authors can be a useful aid in assessing the risk of corrosion damage in glycol injection lines and pipelines, associated with the presence of oxygen in the lean MEG.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)