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Collaborating Authors
Economides, M.J.
Abstract Beyond everybody's price forecasts—including ours, which, a year earlier, was considered at $6 to $7 the most outrageous in the industry—natural gas traded at over $10 per thousand standard cubic feet during the winter of 2000–2001. On a basis of British thermal units, or BTU value, this price was equivalent to more than $60-a-barrel oil. The emergence of natural gas as the premium fuel is a process that has been both transparent and compelling. It is an important stage in the de-carbonization of fuels; starting from wood, to coal, to oil, to natural gas, and eventually hydrogen. The transformation is a historical imperative, and it is our contention that irrespective of the price of natural gas, there is no going back to oil or coal for a wide range of energy needs. The problem is not the price; the problem is supply, and the potential for shortages. Looking beyond the very likely shortage scenarios, where is the extra natural gas going to come from, now slated to increase over the next decade from 23 trillion cubic feet to at least 30 trillion, and perhaps 33 trillion? There are four potential sources:Increases from existing producing areas in the United States, such as the Rocky Mountains. Massive deposits of Alaskan gas. Natural gas from the Gulf of Mexico at depths of 5,000 feet and more. There are copious amounts of gas in the area, but few companies have targeted geologic structures just for gas. Incoming gas in the form of liquefied natural gas, or LNG. With a massive influx of capital and an urgent relaxation of the government permit process, LNG may be one of the best options – in the short (three years) to intermediate future (ten years.). Introduction This paper is written against an extraordinary backdrop: a recent market price of $10 per thousand standard cubic feet (Mcf) for natural gas, never before seen in either nominal or real dollars at the Nymex, and over $60 per Mcf on the spot market in California. While the energy content of one Mcf of natural gas is about 1/6 of the energy content of a barrel of oil, it has traded traditionally around 1/8 of the price of oil. The price has also been quite stable without the wild gyrations in the price of oil. This winter's run-up in natural gas prices has reversed both of these trends. A spot price for natural gas of over $60 per Mcf is equivalent to oil at almost $400 per barrel! This situation has prompted many to suggest that the natural gas trends of the last few years may be reversed and, in fact, and the price increases may dampen the great enthusiasm that both society and the energy markets—from space heating to power generation to transportation—have shown for natural gas. We think not. The de-carbonization of fuels is a historical imperative, motivated not only by real or imagined environmental concerns, but also by compelling efficiencies and, especially, technological evolutions. This situation is similar to the passing of the steam engine era. There is no doubt that today's technology could build a steam engine far superior to those of the nineteenth century, but "once you go gasoline (or natural gas), there is no going back." We have addressed these issues in a recent paper. In that paper we also provide estimates of our forecast for future use of natural gas which we put at almost 33 Tcf by the year 2010, compared to 23 Tcf today. Other estimates are summarized in Fig. 1. In all cases the projected demand is extraordinary and it will put a very large burden on supplies.
- North America > Canada (1.00)
- North America > United States > Texas (0.94)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Lobo Field (0.99)
- North America > United States > Texas > Anadarko Basin (0.99)
- North America > United States > Oklahoma > Anadarko Basin (0.99)
- (3 more...)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Liquified natural gas (LNG) (1.00)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Compressed natural gas (CNG) (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (0.96)
Natural Gas: The Revolution Is Coming
Economides, M.J. (U. of Houston) | Oligney, R.E. (U. of Houston) | Demarchos, A.S. (MJE Consultants)
Summary Natural gas today accounts for approximately 22% of world energy demand. This figure is skewed because of the 26% gas market share in the U.S., the biggest consumer. In Europe, outside of the former Soviet Union, with a population of 1.5 times that of the U.S., gas accounts for 19% of the market. In terms of per-capita energy consumption, the average U.S. citizen consumes approximately 2.2 times more gas than a European. These ratios for both total usage and gas market share in the energy mix became much more lopsided for almost all countries. A move toward increasing gas use is now under way, from both demand and supply standpoints. For example, Brazil (the world's 10th largest economy with a current gas market share of 5%) has embarked on a very ambitious plan to increase gas use. Several gas-producing countries also announced ambitious plans for markedly increasing gas output: Qatar, Oman, Venezuela, and Saudi Arabia. Liquefied natural-gas (LNG) facilities are currently being built, and serious LNG tanker shortages are forecast for the next 3 to 4 years. The U.S. has made an emphatic move toward increased gas use. Already less than 5% of electric-power generation uses oil; natural gas will fuel well over 90% of new power generation built in the U.S. over the next decade. Gas-fired turbine manufacturing has a 3-year backlog. Once manufacturing catches up with demand, the transition to natural gas will cause substantial shortages for a considerable time. This will cover new peaks associated with summer electricity demands, not just the traditional peaks in winter heating. More crucial, we believe that environmental concerns, real or imagined, will push the emergence of fuel cells much faster than currently envisioned. Natural gas will be in the center of this transformation, resulting in a greatly expanded market share of gas in the world energy mix, increasing to 40 to 50% by 2020. We present a comprehensive analysis of the current state of natural-gas supply and demand. We provide the conventional forecasts and rationalize our forecasts, which are heavily influenced by electric deregulation, LNG conversion, and fuel cells. Introduction At the time of this writing, natural-gas consumption in the U.S. reached an estimated 23 Tcf/yr, close to the highest consumption rate of natural gas, which occurred during 1972-74. Fig. 1 presents the history of natural-gas consumption in the U.S. and the other G-7 countries (Canada, France, Germany, Italy, Japan, and the U.K.). Of significance is the dip in U.S. gas consumption after 1974, with the low point experienced in 1986 (˜16 Tcf) followed by a subsequent increase of annual consumption at a rather steep pace. The second important conclusion is that the annual rate of natural-gas consumption of the other G-7 countries is significantly below that of the U.S., suggesting a potentially much steeper future annual increase to catch up. Together, with a combined population 1.5 times that of the U.S., these countries consume only three-fourths as much natural gas (17 vs. 23 Tscf/yr). Russia, the world's eighth largest economy, consumes 15 Tcf/yr of natural gas, nearly as much as the consumption of Canada, Germany, the U.K., Italy, France, and Japan combined. Of all the nations in the world, only the U.S. and Canada have the pipeline network in place to take the natural gas from the well to the market. For all others to develop natural gas for both domestic consumption and export, several issues (e.g., regulatory and cultural) have to be resolved to attract the necessary financial and technical investments. Venezuela, with the second largest natural-gas reserves in the Western Hemisphere, has plans to develop its natural-gas industry reserves by using its domestic market as an impetus. The Amazon region, more specifically Peru and the Brazilian Federal States of Amazonas (Acre and Rondonia), has been constantly mentioned as the next place for development for massive natural-gas usage in the Western Hemisphere. The Asia Pacific region, with rapidly emerging and large economies, is likely to augment the already highly developed Japanese natural-gas activity. This includes increasing demand in indigenous gas supplies, imports and exports of LNG, and a transnational pipeline grid. The Natl. Petroleum Council (NPC) in its December 1999 report forecasts that annual natural-gas consumption in the U.S. is likely to increase to 29 Tcf by 2010 and that this increase will be "beyond" 31 Tcf by 2015. These figures represent 26 and 27% of the anticipated U.S. energy consumption, which is supposed to be 111 and 116 quadrillion Btu (quad), respectively. This 1999 report is a reassessment of NPC's 1992 report. It is noteworthy that even "the most robust scenario projected" in the 1992 report was exceeded by actual gas demand. Environmental regulations and restrictions imposed on facilities that burn fossil fuels were cited as some of the main reasons for this unexpected turn of events. While natural gas is also a fossil fuel, its environmental performance in terms of reduced emissions is far superior to that of oil and, especially, to that of coal. Environmentalism, frequently with an ideological hue and couched in difficult-to-combat imagery, has captured a sizeable portion of the national and international political debate and, unavoidably, the political agenda.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > Qatar (0.24)
- (2 more...)
Pushing the Boundaries of Coiled Tubing Applications
Sumrow, M.H. (Consultant) | Economides, M.J. (University of Houston )
Abstract This paper offers a critical review of the capabilities and limitations of coiled tubing as used in matrix stimulation. A method to determine the effective reservoir thickness that can be treated, as a function of coiled tubing size, wall thickness, yield strength, length and well depth is outlined. The method allows the user to push the boundaries of coiled tubing applications to its practical limits. Introduction Coiled tubing is an established technology that has become indispensable to the petroleum industry. However, it is often used only for utilitarian tasks such as spotting fluids or circulating debris from wellbores. The complete domain of coiled tubing capabilities and limitations is not always taken into account during the design and planning process of drilling, completing and operating oil and gas wells. A lot of stimulation work has been done through coiled tubing, with little thought given to how effective the stimulation job will be, beyond simple placement of acid across the perforations and marginally into the formation at low injection rates. Mediocre stimulation jobs may be performed with coiled tubing, when better design work could result in more effective stimulation and lower zone-by-zone skin values. For design and execution of any CT operation, it is important to understand the pressure and tension limits of the coiled tubing. As coiled tubing strings age, the maximum allowed operating pressure available may decrease. Larger CT sizes are in demand for new service requirements, pushing the technology closer to the tube material performance limits. Factors that affect safe operating life of a coiled tubing string are bending cycle fatigue, corrosion, pressure and tension limits, diameter and ovality limits, and mechanical damage. CT is now in use in wells at greater depths >20,000 feet) and wellhead pressures >10,000 psi), pushing material limits even further. In addition to coiled tubing capabilities and limitations, formation characteristics should be well understood. Ideally, formation properties such as porosity, permeability, lithology, mineralogy and acid response curves would be available for all significant target zones. With proper job design and zone isolation, the net formation thickness that can be effectively treated with a particular coiled tubing unit can be determined. Coiled-Tubing Fatigue Coiled-tubing is always plastically deformed when it is used for well operations. Since the shipping spool and work reel must be sized to accommodate transportation and CT unit configuration needs, the tubing must be bent beyond its yield radius of curvature and plastic deformation becomes unavoidable. For each trip into and out of the well (1 cycle), the coiled tubing is bent 6 times. Repeated coiling and uncoiling result in tensile and compressive stresses, beyond the yield strength of the CT material. This plastic deformation leads to cumulative and regressive changes in the material, known as fatigue and eventually fatigue failure occurs. Even though this fatigue is very real, there is no way of measuring it non-destructively. To ensure safety of operations, therefore, it is vital to understand the nature of fatigue, model coiled-tubing-life and set limits for coiled tubing use as it ages. Various methods exist, to estimate when coiled-tubing should be removed from service or downgraded to a lower category of service application. References 1 through 5 discuss these methods in detail.
- North America > United States > Texas > Harris County > Houston (0.28)
- North America > United States > Texas > Dallas County (0.28)
Abstract Hydraulic fracturing has been the stimulation/completion method of choice for the vast majority of gas reservoirs throughout the world. There is no fundamental difference in the design of hydraulic fractures in reservoirs of any permeability. However, for low-permeability reservoirs, obtaining the indicated length of the hydraulic fracture has been the key element in the execution of the stimulation treatments; for high-permeability reservoirs increasing the fracture conductivity (width multiplied by fracture permeability) is important. For the latter, "tip screen-out" treatments have been developed. Damage to the fracture, which causes a reduction in the well performance, has manifested itself in two ways, 1) reduction of the proppant-pack permeability because of polymer residue, choking of the near-well region and over-displacement and 2) damage to the fracture face, i.e., reduction to the reservoir permeability normal to the fracture, because of polymer leakoff during the fracture execution. Both types of damage affect primarily higher-permeability formations, the first reducing the much-desired large fracture conductivity and, the second, providing an impediment to flow, which becomes important because of short fracture lengths. For long fractures and short penetrations of fracture-face damage the reduction to the well performance is insignificant. In gas-condensate reservoirs a situation emerges very frequently that is tantamount to fracture-face damage. Because of the pressure gradient that is created normal to the fracture, liquid condensate is formed which has a major impact on the reduction of the relative permeability-to-gas. Such a reduction depends on the phase behavior of the fluid and the penetration of liquid condensate which, in turn, depends on the pressure drawdown imposed on the well. These phenomena cause an apparent damage, which affects the performance of all fractured wells irrespective of the reservoir permeability (including very low-permeability values). Well testing of such wells would invariably calculate much shorter apparent lengths than actually placed. We are presenting here a model that predicts the fractured well performance in gas-condensate reservoirs, quantifying the effects of gas permeability reduction. Furthermore we present fracture treatment design for condensate reservoirs. The distinguishing feature primarily affects the required fracture length to offset the problems associated with the emergence of liquid condensate. Also, guidelines for the calculation of the appropriate pressure drawdown during production to optimize well performance are provided. Introduction In a two-phase depiction of petroleum oil and gas, the phase envelop describes a dew point pressure curve that starts at the pseudo-critical point (pseudo-critical pressure and pseudo-critical temperature) and curves to the right until it reaches a maximum temperature value, the cricondentherm. Between these two temperature values, liquid emerges as the pressure declines below the dew point value (at a constant temperature). As pressure continues to decrease the amount of liquid in the reservoir increases. However, after a certain limiting value, further pressure reduction causes liquid to re-vaporize. This is the region of retrograde condensation. Many natural gas reservoirs behave in this manner. During production from such reservoirs, the pressure gradient formed between the reservoir pressure and the flowing bottomhole pressure is likely to result in liquid condensation near the wellbore. The producing rate of gas condensate reservoirs is affected greatly by the flowing bottomhole pressure and not only because of the pressure gradient in the reservoir. The value of the bottomhole pressure controls the amount and distribution of liquid condensate accumulation near the well with an unavoidable relative permeability reduction.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Natural Gas: The Revolution Is Coming
Economides, M.J. (University of Houston) | Oligney, R.E. (University of Houston)
Abstract Natural gas today accounts for about 22% of the world energy demand. This figure is skewed because of the 26% gas market share in the biggest consumer of them all, the United States. In Europe, outside of the former Soviet Union, with a population of 1.5 times that of the United States, gas accounts for 19% of the market. In terms of per capita energy consumption, the average U.S. citizen consumes about 2.2 times more gas than a European. These ratios both for total usage and gas market share in the energy mix became much more lopsided for almost all countries. A move toward increasing gas use is now under way, both from a demand and supply standpoint. For example, Brazil, the world's tenth largest economy with a current gas market share of 5%, has embarked into a very ambitious plan of increasing gas use. Several gas-producing countries have also announced very ambitious plans for markedly increased gas output. These include Qatar, Oman, Venezuela and, potentially the largest of them all, Saudi Arabia. Liquefied Natural Gas (LNG) facilities are currently being built, and LNG tankers are forecast to experience very serious shortages over the next three to four years. The United States has made an emphatic move toward increased gas use. Already less than 5% of electric power generation uses oil. Well over 90% of new power generation built in the United States over the next decade will be fueled by natural gas. Gas-fired turbine manufacturing is experiencing a three-year backlog. Once manufacturing catches up with demand, the transition to natural gas will cause substantial shortages for a considerable stretch of time—covering not just the traditional peaks in winter heating but also new peaks associated with summer electricity demands. More crucial, we believe that environmental concerns, real or imagined, will push the emergence of fuel cells much faster than currently envisioned. Natural gas will be in the center of this transformation, resulting in a greatly expanded market share of gas in the world energy mix, increasing to 40–50% by the year 2020. We present below a comprehensive analysis of the current state of natural gas supply and demand; we provide the conventional forecasts and rationalize our forecasts, which are heavily influenced by electric deregulation, LNG conversion and fuel cells. Introduction At the time of this writing, natural gas consumption in the United States has reached an estimated 23 trillion cubic feet (Tcf) per year. This is very near the highest consumption rate of natural gas, which was experienced in the 1972–1974 period. Figure 1 presents the history of natural gas consumption in the United States and the other G-7 countries (Canada, France, Germany, Italy, Japan and the United Kingdom).
- Europe (1.00)
- North America > United States > Texas (0.28)
- Asia > Middle East > Qatar (0.24)
- (2 more...)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- (2 more...)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Main Pass > Block 19 > G-7 Well (0.89)
- North America > Canada (0.89)
- Europe > United Kingdom (0.89)
- (3 more...)
Abstract Whether due to the lure of deep-water prospects or the shear excitement to apply new technology, the recently developed multibranch wells are likely to play a crucial role in the future of petroleum exploitation. The challenge is to adjust and even develop reservoir management strategies both suited to and taking advantage of this technology. In effect, a multibranch well provides an underground gathering system. When the design includes downhole separation that provides for the production at the surface of desired fluids with reinjection of unwanted ones, the well incorporates an underground production facility. To achieve these sorts of objectives, the entire system of branches, completions, manifolds, separators, etc., must be in place and operational before the well can begin to produce. The design considerations that would enable this result rely on a modular approach to the problem and provision for contingencies for uncertainties in the reservoir description and in the reliability of the underground system. This paper outlines the issues that must be considered and provides a framework for the well design process. Introduction In a previous paper, Ehlig-Economides, et al., outlined a modular approach for designing multibranch wells that is reproduced in Figure 1. This figure focused mainly on primary production considerations and on applications where a multibranch well is an option among competing alternatives. For remote or deep offshore locations, the multibranch well offers advantages that make this technology the obvious first choice. For deep-water developments, a key consideration is the need to minimize the sea floor footprint. The ultimate objective would be to develop a significant prospect with a single point of entry, that is, a single subsea wellhead. To minimize or eliminate direct intervention for the life of the project, sensors and controls enabling remote adjustments can be built into the well design. The same well may enable both primary production and pressure maintenance providing for at least 50% recovery of the original oil in place. A fully integrated design addressing planning, construction, and operation must encompass economics, appraisal, reservoir management, surface and underground facilities, branch completions, and drilling, and all with an eye on managing risks and uncertainties. Although the drivers for the design are special to deep-water and remote locations, the technologies employed may offer advantages in less hostile environments as well. Economics The economics justifying production from deep-water reservoirs must compete favorably with global project alternatives. As an example, suppose $1 billion are available for investment. Assuming a risk-loaded discount factor of 0.5, and after tax revenue per barrel of $7.5, the target oil production rate is 182 MSTB/D. In turn, production at this rate provides a 30% rate of return on investment after 3.5 years and is equivalent to an activation index of $5500/STB/D. In 3.5 years, the cumulative production is about 235 MMSTBO. If this is primary production under expansion drive, the recovery factor could be as low as 5% or less, and the initial oil in place would have to be at least 20 times the cumulative production, or 4.7 BSTBO. Globally, there are very few reservoirs of this size. Further, for a single point entry well to produce this volume, it would have to cover an enormous area. A better approach would be to design the well to produce with pressure maintenance via water injection. This exploitation scheme can deliver at least 50% of the oil in place, and the required reservoir volume would be only 470 MMSTBO. The area to be covered by the well would be less by an order of magnitude. Reservoir Management Strategy Deep-water reservoirs are typically younger deposits than land reservoirs at equivalent depths. For a reservoir depth 5000 ft below the sea floor in a 10,000 ft water depth, the overburden stress is due to the combination of the sub sea floor accumulation and the water. Normally pressured and poorly consolidated or unconsolidated formations are expected with significant light oil or gas reserves.
- Asia (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.36)
Abstract Petroleum production grows from frontier to semi-mature to mature. There have been several attempts to quantify a petroleum region's production profile, including seminal works by Hubbert and others. Both the physics of production and the economics of exploitation are presumed to influence this profile. Defying the log-normal distribution which was suggested by Hubbert, entire petroleum provinces have extended their production history into a much flatter and considerably wider profile, recently characterized as fractal. Maturity implies, among other characteristics, small pool exploration, commoditized drilling and, especially, production enhancement services. We suggest that the transition in the production profile is characterized and at the same time aided by the flight of the major service company (which has become even bigger and more diversified) and its replacement by smaller service companies. There are significant distinctions between the local and international service companies. These include issues such as local vs. global knowledge, non-integrated vs. integrated services and a low vs. high comfort level by the clients. The mix of the local service companies can be greatly affected by the local operators. It must be emphasized that the quality and spectrum of services are crucial elements for the survival of the local petroleum production. We present here a model for the local service company/operator interaction, the changing role of the major service companies and criteria for technology utilization and required proficiency. We apply these concepts to a highly mature area (Oklahoma) and to Oman, entering maturity now. Introduction In our view, two extraordinary events have resulted from and further exacerbated the ongoing slight but important imbalance between petroleum supply and demand:a substantial recent reduction in petroleum prices and a consolidation of the upstream petroleum services sector. The reduction in the petroleum prices although triggered by larger economic problems in Asia has, again, shown the precariousness of the current production and, especially, trading scenarios. It has also reinforced the fickleness of petroleum prices. No other commodity can suffer a 50% price reduction because of a reduction of a fraction of one percent in projected demand. The reduction in petroleum prices has resulted in the usual problems in petroleum producing countries with larger populations such as Venezuela, Indonesia and Nigeria, and a marked decrease in the earnings of multinational petroleum companies. The capitalization of the service sector went through a dramatic depression in the course of a few months. In some cases the stock prices fell by 75%. It is in this environment that the service sector underwent a widely expected consolidation, into a handful of mega-service companies, a consolidation that has been gradually ongoing for several years and was prompted by much longer-term considerations in the exploration and production (E&P) business. The role of the four current, all encompassing mega-service companies (Schlumberger, Halliburon, Baker Hughes and BJ Services) has been steadily expanding in the last decade, encroaching into areas that were previously the exclusive domain of petroleum producers.
- Asia > Middle East > Oman (0.28)
- North America > United States > Oklahoma (0.27)
Abstract Petroleum well production impairment has long been associated with formation damage. Concepts such as the skin effect and its various manifestations have been introduced to account for the effects of damage. The origins of damage and the types of damage have also been the subjects of intense scrutiny. Abatement has included preventive measures such as the use of "non-damaging" fluids, presumably more benign processes, and improved drilling and well construction procedures and techniques. Once in place, the removal of damage has spawned an entire industry, that of matrix stimulation. This involves the use of appropriate remediation fluids, complete with the understanding of the often contrasting interaction among these fluids, the fluids and the damage, and very importantly, the side-effects which can damage the well more than its pre-stimulation state. Again, appropriate hardware was necessary. Due to the fact that damage removal is often either incomplete or unsuccessful, methods of by-passing the damage, such as high permeability fracturing, have been developed. Finally, brute force approaches are common, including the drilling of more vertical and/or horizontal wells regardless of the damage in order to get enough production. This paper is a critical review of both the evolution of the technologies and the thinking processes that have permeated the industry over the past quarter century. Particular emphasis is given to the resolution of controversial subjects and their impact on the field. These include issues such as matrix stimulation versus fracturing, sand production control versus sand de-consolidation management, underbalance versus extreme overbalance, perforating and drilling fluids and practices. Introduction A routine procedure of early-day operators to keep many wells in production was "clean out, shoot, clean out again." Therefore, the idea of formation damage abatement has not been an esoteric phenomenon to the industry. Engineers have long yearned to prevent, diagnose and remediate formation damage. The disagreement has been how to accomplish it. These concerns continue to permeate within the literature and various technical gatherings. Finally, the Society of Petroleum Engineering (SPE) approved the formation of a formal symposium. The first Symposium on Formation Damage Control was held in 1974 in New Orleans, LA. This was followed by symposia in Houston, TX (1976), Lafayette, LA (1978), and Bakersfield, CA (1980). The location of the symposium alternated between Lafayette and Bakersfield until 1990, when Lafayette became the sole host of the symposium. (Table 1). In 1992 the SPE Board approved the international designation for the symposium. The year 2000 Symposium is the silver anniversary of the event. During its 25 years of existence, the symposium has grown from a regional event to today's major international symposium, attracting over 800 participants from more than 30 countries representing 6 continents. The success of the symposium prompted the initiation of the sister conference during the off years in the Hague, the Netherlands, beginning in 1995. The International Symposium and Exhibition on Formation Damage Control (ISEFDC) has provided nearly 600 technical papers to the literature (Tables 1 and 2). We have selected what we consider as some of the most important topics in damage, damage characterization, prevention and abatement. While this paper by no means exhausts the subject, it is a reasonably comprehensive description of the evolution of both the technology and, especially, the thinking process over the last 25 years.
- North America > United States > California > Kern County > Bakersfield (0.46)
- North America > United States > Louisiana > Lafayette Parish > Lafayette (0.42)
- North America > United States > Texas > Harris County > Houston (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline (0.93)
- Geology > Mineral > Silicate (0.69)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.99)
- North America > United States > Alaska > Cook Inlet Basin > Trading Bay Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Main Pass (0.98)
In creating complex well architecture a primary exercise is the initiation of a second branch from an existing "parent" or "mother" hole. The latter can be vertical, inclined or horizontal. The branch can be initiated at a range of angles depending on the drilling hardware used. In creating this angled branch from the main branch the stress concentration at the juncture depends greatly on the state of the far field stresses and their relative magnitudes and the mechanical properties of the rock. This work shows the calculation of the resulting state of stress at an open-hole juncture of two wells and along with a failure criterion delineates the stability of the new hole. The analysis is carried out for an angle of kick off of 2.5° and rock mechanical properties and far-field state of stress characteristic of a formation in Lake Maracaibo, Venezuela. Comparison of the estimated state of stress by the model and the rock failure criterion, predicts no mechanical instabilities at the juncture for this case. The analysis presented here demonstrates that it can be a useful tool for planning multilateral/multibranched wells by seeking formations that can withstand the stress imposed at the kick-off point and by orienting the initiation of the second branch in a direction that can ensure stability at the juncture.
- South America > Venezuela > Zulia > Maracaibo (0.25)
- North America > United States > Kansas > Cowley County (0.25)
Summary The near-wellbore fracture geometry is important to hydraulic fracture execution and the subsequent post-treatment well performance. A fracture from an arbitrarily oriented well "cuts" the wellbore at an angle and this limits the communication between the wellbore and reservoir. The stress concentration around the wellbore further complicates the near-wellbore fracture geometry. The fracture width at the wellbore can be much smaller than the maximum width, or it may even close when the fracturing pressure decreases below some critical value. The limited communication path may cause a "screenout" during fracture execution or large reduction in the subsequent production because of choked fracture effects. This paper first discusses fracturing conditions for an optimal communication path between the wellbore and the reservoir. The near-wellbore fracture geometry is then determined. The effects of this fracture geometry on fracture execution and production are discussed. Critical fracturing pressures are also calculated for different wellbore orientations and in-situ principal stress magnitudes. Guidelines are provided to enhance the success of fracturing treatments. Introduction Unless deliberate actions are taken during drilling, the orientation of deviated and horizontal wells rarely coincides with the principal stress directions. Fracturing these wells involves different mechanisms compared to those for vertical wells. Several researchers have demonstrated that fracturing a deviated or horizontal well often results in multiple fracture initiations, near-wellbore fracture reorientation, starter fractures eventual link-up, and near-wellbore fracture width reduction. Yew and Li studied the deviated-well fracture initiation and demonstrated theoretically that fracture reorientation occurs in the very near-wellbore region. The influence of the wellbore on stress distribution decreases rapidly with distance r (proportional to 1/r). Abass, Hedayati, and Meadows and Hallam and Last explored this phenomenon experimentally and showed that the creation of nonplanar fracture geometries such as multiple, T-shape, and reoriented fractures depends on the wellbore direction relative to the in-situ stress field. An optimum wellbore azimuth is necessary to avoid the creation of undesirable fracture geometry. Sousa attempted to solve this problem numerically using fracture mechanics principles. Narrowed near-wellbore fracture width and fracture tortuosity can lead to proppant bridging and premature screenouts. Even if brought to successful execution, tortuous fractures with narrowed near-wellbore width are likely to be choked with considerable reduction in the post-treatment production performance. In this paper, the following problems are addressed: The effects of well orientation and in-situ principal stresses on fracture initiation. The study is based on stress analysis. Generalized type curves are developed to guide perforation design and provide information on optimal well orientation for fracturing. Fracture tortuosity in the near-wellbore region. During propagation the fracture turns and adjusts toward the direction of minimum resistance. This path has a great impact on the near-well fracture geometry. A simple-to-use criterion is presented to predict the fracture orientation and width. The choke effect of near-wellbore fracture on fracturing execution and post-treatment well production. The effects of narrowed near-wellbore fracture width on hydraulic fracturing and post-treatment production are investigated in this section. It is, of course, obvious that these effects will be different for different well deviations and perforation orientations (phasing). Certainly, a perfectly vertical well or a horizontal well in the longitudinal to the fracture direction and using 180° perforation phasing that can be oriented, will eliminate many of the problems addressed in this paper. Fracture Initiation in an Arbitrarily Oriented Wellbore An arbitrarily oriented wellbore is defined within two coordinate systems as shown in Fig. 1. A global coordinate system (a) corresponds to the in-situ stresses while a local coordinate system (b) is defined by the wellbore orientation. Two angles are used to describe the orientation of a deviated wellbore in the global coordinate system: angle a, formed between the in-situ minimum horizontal stress and the projection of the wellbore on the horizontal plane; and angle ß, with which the wellbore deviates from the vertical direction. Fracture initiation is discussed in the local coordinate system, and the fracture initiation position angle ? is relative to the reference axis xx. For any wellbore, the magnitude and orientation of the in-situ stresses result in the local stress concentrations. These induced stress concentrations are significantly different from the "far-field" stress values. An arbitrarily oriented wellbore complicates the state of stresses further. Analytical solutions of stresses around a deviated wellbore were presented by several authors, A three-dimensional (3D) view of stress component distribution around a deviated wellbore is shown in Fig. 2. There are two important points that are warranted here. First, the near-well stress concentrations happen within a few wellbore diameters (approximate 5). Second, there are specific angles (two each) at which stresses s? and sr exhibit minima and maxima. This is an important issue and is expounded upon below.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (1.00)