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Collaborating Authors
Technical Meeting / Petroleum Conference of The South Saskatchewan Section
Abstract "Retention of key employees in the oilfield service sector ". Prior to 1994 Core Laboratories offered its employees little in the way of company benefits. In fact, the company followed governmental guidelines, which in the majority of cases, were minimal. The company movedf?om being part of a multinational to an independently owned organisation in 1994. At this time, there was recognition that tfthe newly created company was to be successful in a competitive environment then retention of its key employees was essential. A series of concrete measures were introduced in October 1994. This included health, long term disability and dental beneJts and a profit share component to all employees. In addition, for key employees, discretionary bonuses for non-management employees, management incentive plans and stock options were introduced This paper discusses the benefit and incentive plans, its cost and the impact it has had on the company's employees. Finally, there is interpretation on how successful the plan has been since its inception. Introduction Core Laboratories (Core) was formed in 1936 in Dallas Texas. In 1949, the company created its first international office - in Edmonton Canada During the next five decades the company expanded its overseas locations and now operates in more then 50 countries and has over 100 facilities worldwide. In 1984, the company was purchased by a multinational organization. Ten years later, in 1994, a Management Buy Out of the company took place. In September 1995, the company became publicly traded on the NASDAQ stock exchange. In 1998, the company listing changed from the NASDAQ to the Dow Jones. Prior to 1994, the company adopted local country benefit plans as stipulated by the Government of the day. Clearly, this approach meant that Core had many different benefit plans in place or in some situations no benefit plans at all, if the law of the land allowed such an approach. The company at this time viewed the lack of or minimal benefits plan as a cost saving venture. The parent company did not take into account the affect on morale, employee retention and loyalty that these limited plans provided. The change of ownership in 1994 presented the opportunity for Core to re-assess its benefits package and introduce an incentive plan for its worldwide employees. BENEFITS In some countries of the world (many of the Middle East countries for example), health and dental services are provided free of charge while others provide limited or no benefits to its employees. It was these latter categories that Core wished to address. The benefits introduced to Core's worldwide employees were based upon modified Canadian and United States plans. Basic health care and hospital accommodations for the employee and dependents were introduced to all regions. This was compulsory for all employees. Core and the employee share the cost. Additional extended health care was introduced. on a voluntary basis, to cover items such as home nursing care, physiotherapy, prescription drugs, injury and illness coverage when travelling internationally. Both employer and employee again share the cost.
- North America > United States > Texas > Dallas County > Dallas (0.25)
- North America > Canada > Alberta > Census Division No. 11 > Edmonton Metropolitan Region > Edmonton (0.25)
- Health & Medicine (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Banking & Finance > Trading (1.00)
Abstract Plugging of horizontal wellbores can lead to significant loss of productivity and can nullify, the benefit of a horizontal wellbore that is expensive to create. Cleaning horizontal wellbores is a formidable challenge. The problem is particularly complex for heavy oil formations that show asphaltene, sand and other difficultto- remediate problems. This papers aim is to develop a new technique that can effectively clean up a horizontal wellbore without requiring expensive workovers. The technique involves the use of ultrasonic treatment coupled with foam treatment. Initial experiments show that ultrasonic treatment can reduce plugging in two waysthe first is the reduction in oil viscosity (especially in the presence of asphaltic crudes) and the second is the ability of ultrasound to keep particles in suspension. The second effect can be due to generation of microbubbles. The process is coupled with in situ generation foam. In order to generate foam, a particular fYPe of surfactant is chosen from a selection of a wide range of surfactants supplied by the service companies. While the design of the device that couples both these effects need to be optimized, initial series of experiments show goodpromises. Introduction Crude oils produced in many parts of the world contain asphaltenes. Asphaltenes are known to deposit in the vicinity of production wells during miscible floods, after acid stimulation, during thermodynamic changes, and in the pipelines during transportation or during pressure changes in a mature field with an asphaltic crude. Asphaltene deposition leads to production loss and involves expensive corrective measures. This study proposes a new technique for cleaning asphaltenes with an ultrasonic device. The same method can be used to clean a horizontal wellbore that usually suffers from solid deposits, leading to significant reduction in productivity. The principle behind this new technique is ultrasonic irradiation, coupled with foam treatment. Even though ultrasonic treatment has been used in other disciplines for cleaning purposes, the petroleum industry has used the technique for remote sensing'" and material characterization. Recently, ultrasonics have been used to reduce cuttings size. This is possibly the first application of ultrasonics in reducing environmental impact due to drilling activities. Several other potential applications of ultrasonics have been investigated, but did not reach commercial level, both in the areas of asphaltene removal and the removal of fines and mud solids from new wellbores. The ultrasonic treatment has been proven to reduce viscosity to facilitate flow in pipelines. The preliminary experiments conducted by the principal author showed that the same ultrasonic technique can be used to clean asphaltene clogged sections of oil wells and reservoirs. Little has been reported, however, on the optimization of amplitude, power generation, time required for cleaning and viscosity reduction. The effect of ultrasonication on adsorption properties of the reservoir rocks and fluids is another area that lacks investigation. Recently, Smordal and Islam demonstrated that the combination of ultrasonic treatment with a jet reactor can be attractive.
Abstract Recent studies on engineering students show that engineering students retain very little in lecture-based. Hands-on courses were introduced in the United Arab Emirates University to integrate laboratory exercises with theory andprinciples. The traditional method that introduces lectures and laboratory classes separately can minimize training in the communication aspects and can lead to diminished creativity and lack-lustre presentation of theory. In contrast to this, the new courses emphasized "hands-on " student learning activities using state-of-the art equipment and sofmare, and interactive self-learning by reducing the amount of formal lectures. For the petroleum engineering program, Properties of Petroleum Fluids and Reservoir Rock Properties were selected for conversion into the new methodology. In the teaching of these courses, the faculty member assumed the role of a manager of learning. In this format, the students were lead through a series of activities that enabled them to master findamental concepts. The backbone of this process is to design hands-on laboratory activities in which students took measurements, and acquired, manipulated and interpreted data in experiments that demonstrate basic concepts. The unique feature of this methodology is the introduction of open-ended problems, creative design, and engineering discussion based on encouraging new ideas. The contents of the selected courses were structured as modules, each of which followed an interactive pattern in which the student was an active partner in the learning process. The interaction was ensured through a set of sequential events: Introductory Lecture, Prelab Presentation and Lab Preparation, Discove y Session, Discussion, and Problem Solving. Evaluation of the course achievements shows that the new methodology promotes the sense of engineering profession, encourages se&education, innovation, and enhanced communication skills. Eventhough students resisted the idea in the beginning, they became enthusiastic as they discovered that they were learning lot more than the conventional approach that separates the lecture-based class ffom the laboratory class. Students' ability to solve problems along with class participation improved drastically. Introduction With the end of the cold war, the world has opened up to new opporhmities. This necessitates revision of engineering curricula. The revision should remedy the shortcomings of the previously established curriculum. The biggest problem of educating engineering students with the knowledge of science has been the lack of integration of research and design. U.S.A. has been trailing in preparing students who can start thinking creative from an earlier age. The inefficiency of lectures in a classroom is becoming increasingly evident. With the advent of internet, students have access to information that cannot be delivered in a classroom lecture, The second major problem with lecture-based teaching is the lack of hand-on experience by students. While some of the universities have implemented the co-op system, in which students are trained by the industry in between academic semesters, students have not been able to see the link between the industry and the academia due to consistent lack of interaction between the two, It appears that this observation of the lack of creativity and hands-on experience is not new.
- North America > United States (0.36)
- Asia > Middle East > UAE (0.24)
Abstract The purpose of this paper is to discuss and forecast the future evolution of technology affecting the petroleum sector in Canada. However it is never sufficient to just forecast technology development. It is important to set the context inwhich the forecast is made. In this case, 8 key issues that can affect petroleum technology are discussed and evaluated- oil prices, global warming, markets, R&D pegormers, government support, the resource base, information technology and deregulation. In the context of these assessments, future technology evolution is predicted for 4 areas - geosciences, production, EOR [enhanced oilrecovery) and upgrading. The forecasts are provided for two time frames - near term (0 to 20 years) and longer term (20 to 50 years). Introduction The purpose of this paper is to discuss and predict the future evolution of technology affecting the petroleum sector in Canada. The time frame assumed is the next 50 years. Two phrases used herein are ""near term", meaning the next 20 years, and "longer term", meaning 20 to 50 years from now. One may think that 50 years is a long time frame, but in the resource business the length of time for new technology to achieve commercial significance is often protracted and underestimated. For example, a multi-lateral horizontal well was drilled in 1953. However, horizontal wells did not achieve commercial significance until the late 1980's. Multilateral horizontals are just now achieving commercial significance - a time lag of over 40 years! This paper is developed in a logical sequence. First it is important to set the context for the forecast - what issues and assumptions are important and can impact the timing or success of any new technologies. Second, sector forecasts are provided with a focus on 4 areas - geosciences, production, EDR and upgrading technologies. Each of these areas can have a major impact on the petroleum sector and is critical for growth and prosperity. Placement of technology in the time frames is based on the authors' view of when the technology will achieve a level of commercial significance. Thirdly, critical factors to achieving the forecast are discussed. Our industry is rife with acronyms and many are used in this report. To help the reader an acronym dictionary is included at the end. Like any forecast on the future there should be disclaimers: This paper does not necessarily reflect the views of our Company, it is a personal view of the future The authors warrant no accuracy or completeness of the forecast. In fact, the only thing known for sure is that, at least in part, the forecast will be wrong and incomplete. Like any forecast, this is a blend of what the authors believe will happen and what they would like to see happen. The reader may choose to view this as a wish list, without seriously changing the intent of the paper.
Abstract Relative permeabilities are complex and important rockfluid properties of reservoirs in which multi-phase flow conditions prevail. Measuring relative permeabilities in the laboratory using cores obtained from a reservoir is a complicated, time demanding and labor-intensive task. There has been limited success in mathematical modeling of relative permeabilities based on rocks and fluid properties due to our inability to simulate the non-linear controlling mechanisms in place. Artificial neural networks (ANNs) promise a potential avenue for implicitly incorporating the controlling mechanisms and parameters into a model that can be utilized as an effective tool for relative permeability predictions. The methodology described in this paper exploits the unique topology of ANNs for determining the two-phase (oilwater) relative permeabilities. The ANN is a universal approximator that performs non-linear, multi-dimensional interpolations. in the development stage of the ANN model, a large number of oil-water relative permeability data sets were collected from the literature. These data sets were used to train the model. In composing the architecture of the ANN, only the readily available rock and fluid properties (endpoint saturations, porosity, permeability, viscosity, and interfacial tension) have been explicitly incorporated. The predictive ability of the model was tested using experimental data sets that were not used during the training stage. The results are in good agreement with the experimentally reported data. The proposed model exhibits sensitivity to several reservoir properties. The proposed ANN model has a dynamic training base that can be expanded as new data become available. Introduction Relative permeabilities quantify multi-phase flow through porous media. Generating an accurate relative permeability versus saturation relationship for each phase is essential for evaluating the performance of a reservoir during primary, secondary, and tertiary production periods. Relative permeability-saturation relationships vary between reservoirs and within a given reservoir. They are non-linear functions of reservoir rock and fluid properties such as phase saturations, formation types, depositional environment, shale content, heterogeneity, porosity, permeability, interconnectivity of pores, pore geometry, interfacial tensions between flowing phases, phase viscosities, phase densities, and rock wettability. Experimental and modeling methods are used for assigning relative permeabilities to a reservoir. Although laboratory measurements of relative permeabilities are difficult, they are still the preferred method. Laboratory measurements are technically difficult and require skillful personnel, expensive equipment, and are lengthy to perform. Therefore, estimation of relative permeabilities with mathematical models has always been an attractive goal. The accuracy of relative permeability values must be preserved. Relative permeability models are commonly used only as estimation tools. Mathematical models for relative permeability can be classified under four main categories: capillary, statistical, empirical, and network models. These models require some rock and fluid properties such as endpoint saturation values, porosity, absolute permeability, interfacial tensions, and viscosity of phases, and incorporate important assumptions. The models are restricted by their assumptions, are not universally applicable, and may be difficult to update for different systems. Empirical models and pore-network models are frequently used and are the most successful in estimating relative permeabilities. Predicting the relative permeability values using mathematical models is
Abstract The current available equipment used in the laboratory to measure permeability of the core samples is very limited. This is because permeability is measured only in one dimension and the faces of the core samples are damaged due to the grain repositioning during sample cutting. The only way to measure permeability is by using a nondamaged sample by chipping it off from the rock. This situation occurs only with drilling cutting samples. New laboratory equipment was designed to measure permeability of the cutting samples. A probe is used in this equipment which is easy to change to accommodate different cutting sample sizes. While using any cutting samples, three different perpendicular points are used and their permeability values measured. When two permeability readings are identical, they quantify the plane permeability. This method of permeability measurement is considered more realistic because: most of the cutting faces are minimally damaged. This equipment is very simple to use, operate and maintain in the laboratory. The equipment is light and portable and can also be used in the field. Introduction The current permeameters used in the oil industry to measure rock permeability require core samples of certain length and diameter. For example, the gas/liquid permeameter require core samples of 1.5 ร 1.0 - core sample size. During cutting in the laboratory most part of the core sample is invaded by the water used to cut the sample. The presence of water and core cutters causes certain damage to the faces of the core samples. Sharpening the inlets and outlets of the core sample using core cutter cause repositioning of the gram. This occurs while a gram is removed during cutting and repressed or positioned as water flows over the edge. This gram repositioning causes the reduction of permeability. On the other hand, if the water used to cut the core sample is incompatible with the clay stability in the core, this clay may swell causing permeability changes. Permeameters that use pressure decay on a long core sample have the same problems('). In addition, this type of equipment can measure permeability in two directions only. As a result, permeability of the core samples does not represent the real rock permeability. Experience showed that core samples permeability is in the range 6570% of the real permeability. This is based on comparing the measured permeability to the calculated permeability from logging data. The Core Measurement System (CSM) has the same disadvantage. Since core samples have high level of heterogeneity, either an average permeability can be calculated or certain points should be chosen along the core sample(2l. The rock heterogeneity is a good reason for getting permeability from cutting samples since they are available. Permeability can also be calculated from well testing data, however despite being more accurate, this method is quite expensive. Another way to measure permeability is by using formation tester from service companies. However, in the vicinity of packer in the high permeability rock the drawdown pressure is too small to be accurate.
Abstract The removal liquids from low-pressure gas wells is a serious problem for the petroleum industry. Many wells have to be shut-down prematurely because of the accumulation of water, condensate or both in the wellbore. Several techniques have been developed so far to combat this problem. Foam lifting is one such technique that has been used quite successfully in the field for removing liquids from the wellbore and the annulus. However, there is a strong need to know at which conditions foam injection is effective and under which conditions it is not. This paper discusses a systematic approach used to look at the efficiency of foam injection for a wide range of liquid and gas flow rates. A specially designed 40-long flow loop is used in which foam is injected at the bottom of the tubing. The efficiency of liquid removal is measured by comparing the liquid holdups at the end of each period of foam injection. The liquid removal efficiencies are also compared against cases in which no foam is injected (base-cases). Foam shows excellent liquid removal compared to the base-cases. Results also show that the type and concentration of the surfactants used to generate the foam has a strong influence on the liquid removal efficiency. Introduction Gas well load up or liquid loading is defined as the loss of available reservoir energy due to the accumulation of liquids in the wellbore over time. The source of these liquids are - liquids (hydrocarbons and water) condensed from the gas due to wellbore heat loss and free liquids produced into the wellbore with gas (Coleman et al., 1991). Accumulation of liquids near the wellbore can cause severe reduction to complete loss of available transport energy due to a combination of hydrostatic pressure, relative permeability, clay swelling and other effects. In a recent study (Christiansen et al.) it has been reported that the hydrostatic pressure exerted by a 1OOO-ft (328 m) column of liquid is enough to stop gas production from many reservoirs. It only takes about 6 barrels (950 litres) of liquid to fill lOOO-fi of 2-7/8" (73 mm) tubing. To blow liquids out of a well, a minimum gas flow rate of 300 MCFD (8500 m3/day) is needed in wells operating with 2-7/8" (73 mm) tubing at a surface pressure of 100 psig (690 kPa). The study also indicated that out of about 6500 gas wells in Colorado almost 6000 produce less than 200 MCFD (5700 m3/day) and therefore probably suffer from liquid accumulation in the well and producing formation. The study of the critical flow rates, for continuous liquid removal from gas wells has been a popular subject of research for many years. Significant works in this area include those by Duggan (1961), Turner et al. (1969), Tek et a1. (1969), Ilobi and Ikoku (1981), Reinicke et a1. (1987), Upchurch (1987) and Coleman et al. (1991). Several methods of liquid removal has been discussed in the literature (Hutlas and Granberry (1972), Lea and Tighe (1983), Bernadiner (1991), Adams and Marsili (199))
Abstract Groundwater and soil contamination resulted from light nonaqueous phase liquids (LNAPLs) spills and leakage in petroleum industry is currently one of the major environmental concerns in the North America. Numerous site remediation technologies, generally classified as ex-situ and in-situ remediation techniques, have been developed and implemented to clean up the contaminated sites in the last two decades. One of the problems associated with ex-situ remediation is the cost of operation. In recent years, in-situ techniques have acquired popularity. However, the selection process of the desired techniques needs a large amount of knowledge. Insufficient expertise in the process may result in large inflation of expenses. In this study, petroleum waste management experts and Artifical Intelligence (AI) researchers worked together to develop an expert system (ES) for the management of petroleum contaminated sites. Various AI techniques were used to construct a useful tool for site remediaiton decision-making. This paper presents the knowledge engineering processes of knowledge acquisition, conceptual design, and system implementation in the project. The case studies have indicated that the expert system can generate cost-effective remediation alternatives to assist decision-makers. Introduction Automation of engineering selection is important for tbe petroleum industries in which decision for a desired remediation technology at a contaminated site is critical for ensuring safety of the environment and the public. A variety of remediation methods/technologies are available. However, different contaminated sites have different characteristics depending on pollutants' properties, hydrological conditions, and a variety of physical (e.g. mass transfer between different phases), chemical (e.g. oxidation and reduction), and biological processes (e.g. aerobic biodegradation). Thus, the methods selected for different sites vary significantly. The decision for a suitable method at a given site often requires expertise on both remediation technologies and site hydrological conditions (Sims, 1992). In general, soil and groundwater remediation techniques can be divided into two classes depending on whether the pollutant is directly removed/degraded in-place or not, i.e. in-situ or ex-situ. One of the main problems associated with ex-situ remediation is its high operating cost for activities like soil excavation and groundwater pumping. In recent years, in-situ techniques have become popular. However, with in-situ remdiation methods, knowledge on processes and factors controlling the results is lacking, which translates to much inflated expenses. Several mathematical models have been proposed to furnish representations as close as possible to reality of the effects of widely known remediation techniques. Some quantitative models have also been proposed for coupling multiphase flow and transport in a porous medium, with consideration of various remediation strategies such as water pumping, vapor and air venting, and steam injection. All of these techniques rely on human intervention for removing the contaminant. These techniques are fast, but costly. Moreover, most of them are too complex and not easily comprehensible for managers and engineers in industries and government. Therefore, a new approach is needed for developing useful, cost..effective, and user friendiy systems which can be readily adopted by industry and/or government to support decision-making on site remediation techniques.
Abstract Microbial mineral precipitation occurs constantly over the geological time. Recently, a parented technology has been introduced to expedite this bacteriogenic mineral precipitation process. Petroleum geologists have employed the process to selectively plug an unwanted zone in the reservoir to enhance oil recovery. The process induces natural cementation or plugging in sediments or rock formations. The mineral precipitation is induced as a result of microbial activities. Bacteria can deposit minerals directly from the medium through their metabolic activities. They can also precipitate minerals indirectly from the medium by changing regional geological environmental conditions. Mineral precipitations and the dead bacterial cells can persist as a part of the environment and result in plugging or cementing in pores in that environment. The process is optimized with bacteria Bacillus Paiteuni to precipitate CaCO3 so that the bacteriogenic cementation occurs in hours rather than in years It is suggested that the process be used to plug fractures in water-producing zones to prevent excessive water production during oil recovery The same technique can be used to consolidate sands in an unconsolidated formation to prevent sand production. A series of experiments was conducted to investigate the possibility of using microbial plugging process to remediate fractures and to test factors affecting that process. The effects of pH, temperature and medium on mineral precipitation and bacteria growth are studied in detail.Also, the effect of fracture width and fracture fillings is studied. It is found that the microbial mineral plugging technique is effective in plugging fractures, as evidenced through measurement o f local permeabilities and compressive strength. Finally, a mathematical model is presented The model incorporates both bacterial transport and growth within a porous medium. By introducing a phenomenological relationship between bacterial concentration and porosity, the permeability of the system can be accurately predicted. This permeability, then can be linked to the compressive strength and fracture mechanics of the system. The numerical model allows one to optimize operating parameters of a bacterial consolidation scheme. Introduction Microbes (procaryotes and eucaryotes) distribute widely in geological environments. Natural surface rocks have been observed to have 10 bacteria or fungal cells per gram of stone (Eckhardt, 1985). Microbial metabolic activities play an important role in deposition and diagenesis process in a geological environment (Ferris et al., 1988). Microbio-mineral-precipitation is not an unusual process in nature. Minerals such as calcite, silicon, oxidized manganese and oxidized iron usually do not precipitate naturally because of the low ionic concentration. But when bacteria interact with these ions such as Ca, Si, Fe and Mn, precipitation takes place (Beveriidge et al., 1985) and plugging or cementing occurs as a result. Bacteria are found to absorb and precipitate metal in the tresh water of the Amazonian River system (Konhauser et al., 1993). The most abundant mineral phase associated with bacteria is a complex (Fe, Al) silicate with a variable composition. The amount of metal sorption and biomineralization largely reflect the availability of dissolved metals in the water.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Microbial methods (0.62)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.56)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (0.55)
Abstract The most difficult practical operation in the oil industry is to displace oil in the low permeability zones in heterogeneous reservoir. This situation becomes worse when the permeability contrast is high and in the presence of oil and acid. In this study. experiments were conducted to investigate what type of foam is stable to temporurily plug the high permeable cones Different permeability contrasts of Berea sandstone were used for the experiments. These experiments were conducted in the absence and presence of oil followed by acid injection, while foam quality and velocity were controlled. Results show that most of the surfactants were interacting with oil and acid under certain shear rate. Only some specific surfactants (not used in the oil industy) resulted in more stable foam and best acid diverting jobs When water was followed by the acid job, most of the oil in the low permeability zones was removed and flowed out of the rock. Certain foam slug sizes were needed in different permeability contrasts. As a result of the experiments, a simple way was to predict foam rate was observed. Laboratory experiments were performed before the application of the acid job in the field. As a result, less acid might be needed to perform the stimulation job. Introduction The presence of foam in a heterogeneous porous media helps to reduce the liquid mobility in the high permeability layers. This reduction in mobility causes the diversion of most of the liquid to the lower permeability layers. It is generally accepted that foam, in the presence of oil, does not have a reduction in mobility. In laboratory experiments with oil, the foam propagation was usually retarded because of the presence of oil and in some cases there was no mobility reduction until the oil saturation became low enough. Minssieux proposed to use stabilizing agents capable of increasing the viscosity of their aqueous phase (such as a polyvinyl alcohol) to stabilize foams in the presence of oil. In the field application, as Maini reported, the injected foam inevitably contacted some residual oil. This contact between oil and foam had a major effect on foam properties. However, the mixing of the injected foam agent with surfactants already present in the oil led to enhancement of foam properties when the two surfactants behaved synergistically. He also found that the fonnation of oil in water emulsion could be a factor in overall mobility reduction behavior. Nikolov et al reported that during the process of three phase foam thinning, three distinct films occurred: foam films (water film between oil bubbles), emulsion films (water between oil droplets), and pseudoemulsion films (water film between air and oil droplets). Their micromodel experiments showed that after a certain thickness a pseudoemulsion film formed between the oil lens and the air bubble surface ruptures causing the oil to spread on the surface. This oil spread disturbed the mechanical equilibrium between the foam lamellae and their borders causing the entire frame to break.
- North America > United States > West Virginia (0.25)
- North America > United States > Pennsylvania (0.25)
- North America > United States > Ohio (0.25)
- North America > United States > Kentucky (0.25)