Trigos, Erika Margarita (Universidad Industrial De Santander) | Rueda, Silvia Fernanda (Universidad Industrial de Santander) | Rodriguez, Edwin (Ecopetrol S.A.) | Espinosa Ortega, Jose Sebastian (Ecopetrol-ICP)
In Colombia, there are several heavy oil fields where cyclic steam stimulation have been successfully applied for over 25 years and although it is assumed that the reservoir temperature is high and the conditions are ideal for making the leap to
continuous steam injection, some studies apparently show that this technique is not feasible for the reservoir; in fact, between 1992 and 1994, the implementation of a pilot did not reach the expected results.
From this fact raises the question: What are the key factors that ensure the success of a continuous steam injection pilot? To solve this question, a numerical simulation and analytical model based study was performed, showing that the performance of the technique lies in minimizing the energy losses and supplying only the necessary heat according to each stage of the process, these practices are known as heat management.
It was found that critical aspects of heat management are: reducing well spacing, selection of open thickness to injection, perforated intervals, completion design, injector well distance from generator and injection surface line conditions, as well as
constant reservoir temperature monitoring, from which the energy requirements at each stage of the process is determined and avoid an excessive injection rate which goes against project economics.
For the field case it was found that: the well spacing should be reduced from 10 to 2.5 acres, the need of using selective sequential injection scheme (due the interbedded shale), the injection rate should be reduced to 46% a year after starting the
process and also change the type of insulation on the surface lines. In this paper, the methodology and tools used for factor evaluation and process optimization are presented.
Exploration for hydrocarbons continues to expand into frontier environments. The project management, logistical and supply chain challenges of drilling in these areas is increased due to their remoteness. This paper presents the operational challenges and lessons learned from drilling a successful ultradeepwater wild cat exploration well in a logistically challenging frontier environment offshore French Guiana.
Since the following conventions (Rio Convention, Kyoto Convention and South Africa Convention) took place, concerns have been raised about the emission of carbon dioxide gas into the atmosphere by several industrial countries. Currently a few companies at the Point Lisas Industrial Complex, West Trinidad (see Figure 3), produce about 120 million standard cubic feet per day (mmscfd) of CO2 in the form of waste gas. Despite the gas being so readily available and at a relatively cheap price (< US $ 0.25/mscf) there is no reason for the current disposal practice (by venting the gas to the atmosphere), to be allowed to prevail. The carbon dioxide, which is vented, comprises 99.4% pure gas at 117 OF and requires cooling and drying before any compression can take place. Several depleted reservoirs in existing oil and gas fields throughout Trinidad were analyzed for disposal of the carbon dioxide. The only field that fit the criteria for good storage for the next eighty (80) years at the prevailing production rates is the Teak Field, which was previously operated by BPTT (formerly Amoco Trinidad), but is now operated by Repsol YPF (Trinidad). Since this field is located in the Atlantic Ocean, East Trinidad, even if there is a surface breakthrough it would not affect the environment. Thus the Teak Field, which is a depleted oil and gas field, offers a good disposal source for the present carbon dioxide generated at the Point Lisas Industrial Estate for the next eighty (80) years, along with the adjacent fields like the Saaman and Poui Fields offering a further forty (40) years each. The estimated cost for this project will be US $ 160 million which will include upgrading the facilities at both Point Lisas and on the Teak Platforms, and the laying of the 16?? pipeline. Since this project is not revenue generating, it is only being considered for the long term adherences to the international standards for the reduction of carbon dioxide into the atmosphere.
Concerns have been raised about the emission of carbon dioxide gas into the atmosphere during the last ten (10) years. Covering the earth in which we live is a screen of three hundred (300) miles thickness comprising of air (78 % nitrogen, 20.7% oxygen, 0.9 % water vapour and inert gases, 0.03% carbon dioxide, and traces of other gases). Life on earth has adapted to the existence of this blanket and any imbalance or upset conditions (like volcanic activities) can trigger an adverse effect or a chain of reactions. The atmosphere acts an insulator preventing the earth from experiencing very high temperatures. Since we do not own the air we breathe, we can avoid the release of any impurities merging with the air in our daily activities. For example the continued releases of carbon monoxide from the exhaust pipes in vehicles do have an adverse effect in the air composition, likewise the emissions from various stacks in industrial areas (like the Point Lisas Industrial Area). But Trinidad and Tobago is ranked as one of the highest emitter of carbon dioxide in the world (see Table 3).
Carbon Dioxide emissions in Trinidad stem mainly from the industrial estates. There are eleven (11) ammonia plants at Point Lisas that produce CO2 as a waste product. Only eight (8) are highlighted in Table 1. A small amount is used in methanol and urea manufacture. However (as shown in Table 1 below), there is an available 120 mmscfd, which is vented. There exist plants in the Point Lisas industrial estate, which produce carbon dioxide as a by-product from their operations.
Throughout the decades to come world's population is expected to rise as well as the energetic, food and water demand. All that, together with the everyday more rigid international environmental regulations alongside with the ongoing vertiginous technological advancement, will induce to a restructuration of global economy on the inter-governmental and institutional level in order to reinforce the fundamental pillars of sustainability: the environmental, social and economical. New energy systems will be implemented and scarcity of resources will be more severe, leading the economy not only to shift but to adapt to unconventional energy carriers and commodities. This combined with the targeted impact of these policies, concerning living standard improvements, social inclusion and carbon mitigation among others, will raise new and demanding challenges to face. This paper intends to present an overview of the energetic playing field throughout the transition towards a more sustainable world and the role of the Oil & Gas industry within this period. This article will identify and explain the challenges and constraints to be faced as well as the opportunities of undertaking ventures in this shifting environment. Also, the paper will broaden the concept of Green Economy, main theme of the 2012 UN's Conference on Sustainable Development, and present strategies to develop an energy system to function and sustainably endure in time within the mentioned framework and ex-plain why the O&G industry is a fundamental participant and a major "game changer" in this process. Petroleum holds a key role in this transition as being the most widespread energy carrier and the most competitive element of the current energy system. Therefore, the O&G industry has the opportunity to become the main "driver of change" and to impulse a more prosper and sustainable energy network for the world. It's imperative that the O&G sector keeps a long-term perspective in order to remain in force and profitable. This paper pro-poses some guidelines to do so and intends to raise awareness on the fact that sustainability is not only changing the way we analyze a project but moreover the way we do business in the O&G industry.
Einar Steensnaes, Minister for Petroleum and Energy of Norway, said during a speech given at the 2002 World Summit on Sustainable Development and speaking about the Petroleum Industry's perspectives for the future that "Increasingly, good ethics is good business". This simple and brief statement might be one of the clearest and most accurate ways of perceiving where the Energy Industry stands today and how it is preparing to face the challenges that the decades to come will bring. Today, the energy playing field is changing. Technology is advancing at the most vertiginous rate in history and it is only likely to accelerate. Energy has become an integral and fundamental part of human modern society and, most probably, man-kind's dependence and demand of energy will dramatically increase throughout this century. So, how will the Energy Indus-try overcome the complex challenges that ensuring energy security for such a fast moving world mean? The answer is right there: with good ethics.
Hydrocarbon reservoir management of a mature reservoir is a complex process of deciphering the reservoir character, through dynamic static data integration, to produce an ideal depletion strategy for the field. A great result is normally a winning opportunity set or strategy defined by a marriage of maximum hydrocarbon recovery with fantastic economic indicators. Is it any wonder we invest heavily into tools and processes to achieve just this!
This paper will explore the use of structural and reservoir modeling tools and techniques to re-design an optimal depletion strategy for an oil and gas reservoir, in a predominantly gas field, in the Columbus basin off the East coast of Trinidad. This reservoir is a massive ~700 ft sand incorporating a 30~40ft thin oil rim with an underlying aquifer and overlain by a huge gas cap. Both oil and gas has been produced from this reservoir since 1998 by 8 oil wells and 4 gas wells spread across two fields.
Should the future of this reservoir first rely on targeting remaining oil or do we shift into high gas acceleration gear? To solve this conundrum all subsurface hands were brought on deck. The formulation of an appropriate depletion plan requires a multi pronged approach, as a clear alliance must be made between business objectives, reducing risk and good reservoir management practice.
A VIP/Nexus reservoir simulation model was the 'tool of choice' to investigate which depletion direction to forge ahead with. The first stage of this reservoir management investigation was the creation of a reliable structural model which then acted as the foundation for the build of a representative reservoir model. As part of this paper's journey, we delve into the process flow used to mimic this magnificent reservoir. We endeavor to deepen your understanding of, the application of crucial petrophysical modeling in the reservoir characterization procedure and the unmistakable impact of history matching over 12 years of production and pressure data. The result of this work was a fit for purpose reservoir model enabling the operator to make the right decisions for future development of this reservoir.
Fluid systems used for servicing wellbores are usually a combination of particulate materials of varying specific gravity, particle size, aspect ratio, and reactivity, such as lightweight materials/weighting agents, clays, fibers, elastomers, polymers, resins, salts, and cementitious materials in water or oil media. These fluids are more commonly referred to as ?complex fluids? and often exhibit a high degree of non-Newtonian and time-dependent behavior. To more efficiently and expeditiously perform well operations, it is beneficial to accurately probe the rheology of fluids (and their admixtures) under downhole conditions.
A novel, helical-shaped stator-rotor assembly was designed and developed to work around measurement errors arising from sample inhomogeneity, particle separation, wall slip, and coring-related issues with commonly used geometries, such as those of a bob/sleeve and vane. The rotor blade arrangement is a double helix with cut flights, whereas the stator unit has blades that are manufactured by parting a coaxial double helix offset to the envelope of the rotor. Constant relative separation between the stator blades and rotor vanes is maintained in all planes to create shear geometries that enhance in-situ mixing. This was leveraged to conducting compatibility testing.
Torque and rev/min data was collected for eight different Newtonian fluids with viscosities ranging from 10 to 1000 cp. The power number and impeller Reynolds number were plotted to derive functional relationships between these quantities in the laminar and turbulent regimes. Various complex fluids, including fracturing gels, viscoelastic fluids, oil, water-based muds, spacers, and cement slurries were tested on the helical mixer, a triangular impeller, and Couette geometries for comparative mathematical modeling.
A unified algorithm and data analysis protocol featuring the four-parameter generalized Herschel Bulkley model is presented to derive rheograms and yield stress. A comparison of experimental results with computational fluid dynamics (CFD) simulations is also presented.
Drilling engineers frequently make expensive misjudgment due to improper prediction and control of pressure along the wellbore. The flow of fluid in the wellbore is complicated not only by contraction and expansion through tool joints, but also by the effect of pipe rotation.
Field data has proved the excessive pressure drop through tool joint. Extensive experimental and theoretical studies have been conducted to study the effects of tool joint and pipe rotation on pressure loss along the drillstring. However, there is a discrepancy between published studies about the effect of pipe rotation on pressure drop in pipe and annular flow. For Newtonian fluids, it is well known that pipe rotation does not affect the pressure drop. Nevertheless, for non-Newtonian drilling fluids, several experimental works reported the reduction of pressure loss; while other works reported the increase in pressure loss.
In this study, the flow of drilling fluid through contraction and divergence across the tool joint is investigated using Computational Fluid Dynamics (CFD) software package. Different pipe rotation speeds are used to simulate the flow of an incompressible Yield Power Law fluid in both pipe and concentric and eccentric annuli. The velocity and pressure profiles are analyzed and compared to emphasize the effect of tool joint and pipe rotation on pressure loss. The results show that pressure drop through tool joints is significant. Pipe rotation has small effect on pressure drop at low velocity, and different effects on pressure drop at higher velocity. Positive and negative effects depend strongly on flow geometry and flow velocity.
The results of this study provide valuable information about the flow of drilling fluids through tool joints and along the wellbore. These give useful insight into the effect of pipe rotation and tool joint on pressure drop. Accurate calculation of pressure drop along the wellbore with pipe rotation is highly important in hydraulic program, optimization and well control, especially for deepwater wells.
Nonaqueous cement slurries have been used for many years to prevent unwanted water or gas production and to repair holes/cracks or other pathways that could have formed in the casing, cement column, or at the interface. Such slurries were forced or squeezed into flow channels and allowed to contact water being produced or otherwise inherently present. Exposure of cement to water presumably allows for setting of cement, thereby plugging the flow pathway. These nonaqueous cement slurries primarily contained cement, a nonaqueous fluid, and an oil-wetting surfactant. It was generally assumed that contact between cement and water allowed setting of the entire cement mass with ensuing good strength development, even though an efficient dynamic mixing of cement and water under downhole conditions is unlikely. In the laboratory, this is typically demonstrated by mixing (by means of agitation) the slurry and the required amount of water, allowing it to set at well temperatures and measuring strengths.
Laboratory mixing under quiescent conditions by addition of water to the top of nonaqueous cement slurry with no agitation, and allowing it to cure for many days, demonstrated setting of cement only at the interface as a thin solid film, while the remaining slurry was unset. It was not obvious whether the presence of set cement at the fluid interface prevented further ingress of water into the cement slurry, or if the cement particles in the bulk slurry remained too oil wet to allow hydration reactions. It was also not obvious whether a totally quiescent, totally dynamic, or an intermediate level contact between water and cement slurry truly simulated the downhole situation, accounting for the success of the technology. A surfactant combination was designed to allow deeper penetration of water into cement slurry under quiescent conditions. Details are presented.
Drozdov, Alexander Nikolaevich (Gubkin Russian State University of Oil & Gas) | Bulatov, Georgy (Gubkin Russian State University of Oil & Gas) | Lapouhov, Alexander Nikolaevich (Gubkin Russian State University of Oil & Gas) | Mamedov, Emil Adalatovich (Gubkin Russian State University of Oil & Gas) | Malyavko, Evgeny Alexandr (Gubkin Russian State U. of O&G) | Alekseev, Yaroslav L. (Gubkin Russian State U. of O&G)
One of the main reasons, leading to the production decline of gas and gas-condensate wells is the accumulation of liquid fluid on the bottom of the well and formation of liquid blockage. Under certain conditions, bottom hole pressure drops, flow rate
declines and gas velocity reduction becomes insufficient for the liquid lifting. Periodic gas purging of low-pressure wells practiced in Russia for water extraction, leads to the unproductive losses of hydrocarbons and forbids achieving stable operation. It leads to the retirement of wells out of the producing well stock, formation of dead zones with entrapped gas and, as the final result, to the waterflood hydrocarbon recovery drawdown. This problem can be solved by putting low-pressure flooded wells on pump, as international experience being indicative of its benefits.
Various engineering solutions based on the field tests of the techniques, mentioned above, were examined. The most suitable and viable technologies, for one of the Russian fields to be at the latest stage of reservoir development, were electric
submersible centrifugal pumps (ESP) and electric progressive cavity pumps (ESPCP): with the removing of water to the surface and the subsequent injection of water into injection wells, and also with the injection of water into the underlying aquifer in the existing producing well.
We developed a rational method of hydraulic calculation and selection ESP and ESPCP for different operating conditions. Preliminary bench experiments of ESP's, centrifugal gas separators and separator of mechanical impurities were carried out. The equipment has proven its efficiency.
The proposed solution will ensure the efficient functioning of the system of artificial-lift gas and gas-condensate well operation without using the unique expensive equipment. Also in a short period of time it could allow adapting the quantity produced submersible pumps for the conditions of gas industry.