Workplace accidents are responsible for approximately 4,000-5,000 fatalities and 3 million nonfatal injuries and illnesses in the United States each year. The Bureau of Labor Statistics (BLS 2013) has recently presented data that suggest that the construction industry is experiencing an increasing trend for fatal accidents which also includes a disturbing increase in fatalities involving workers who are 16 years of age or younger. The reported trends for general industry may not seem as alarming but, nonetheless, suggest a general lack of effectiveness in current efforts to significantly reduce workplace fatalities and nonfatal accidents.
Many of these workplace accidents are associated with hazards that are well recognized within industry and already included within many of the subject-specific standards promulgated by the Occupational Safety and Health Administration (OSHA). The apparent failure of existing standards has also steered OSHA toward recognizing certain limitations within their current regulatory framework for administrative rulemaking, compliance, and enforcement. The essential elements that are required for effective health and safety management have evolved from knowledge gained in part from OSHA’s Voluntary Protection Program (VPP) and the Safety and Health Achievement Recognition Program (SHARP). Organizations from each of these programs have demonstrated a successful record for recognizing, preventing, and controlling hazards in the workplace. These observations have helped OSHA craft their vision for promulgating a new rule requiring employers to develop and implement an Injury and Illness Prevention Program (I2P2), which was announced through the Federal Register in 2010.
Crosslinking of guar and guar derivatives has played a major role in improving stimulation of oil and gas wells. While crosslinking has been used for a number of years, many facets of crosslinked systems are still not well understood. Part of the problem is that the traditional methods of determining the properties of crosslinked fluids work well for obtaining the data necessary for treatment design, but yield little information about nature of the crosslinked system. A good example of this is found in the development of low polymer concentration crosslinked gels. These gels are important because they lower costs and help to minimize formation damage. In this paper, methods for predicting crosslinkability at low concentrations will be examined.
The polymer literature is filled with methods of characterizing polymer solutions almost none of which find wide use in the development of crosslinked fracturing fluids. Dawson, et. al.,1 first reported that the concentration at which a polymer solution transitions from dilute to semidilute could be used as a method for determining the potential for low concentration crosslinking in a guar or guar derivative solutions. This finding was controversial, to say the least. To test this assertion, we have conducted a series of experiments that not only show that the transition concentration is an important indicator, but also present a framework for exploring the potential of other crosslinked systems. Interestingly, polymers that crosslink well at low concentrations do not always produce the best crosslinked gel at higher concentrations. Based on our experiments, we will present an explanation for this finding. This emphasizes the importance of understanding the crosslinking process in order to optimize the selection of a polymer for a particular application.
This paper examines guar and guar derivative systems used in the industry and reports on a new guar that can be successfully crosslinked at low concentrations. It also provides a outline for studying crosslinking at low concentrations and presents insights into the crosslinking process.
A.M. Przepasniak, Department of Chemical Engineering, The University of Alabama, and P.E. Clark, Department of Chemical Engineering, The University of Alabama
Formation damage by polymers used in drilling, workover, and completion fluids can be a significant problem. In many of the processes that occur in the oilfield, fluid-loss agents are added to the fluids to minimize the loss of polymer containing fluid to the formation. It is well known that certain polymers will filter out on the formation face while other polymers freely enter the matrix. Some polymers will filter in low permeability rock while flowing freely in high permeability rock. This leads to the question of polymer filtration in fluid-loss agent and drilled solids filter cakes.
Hydroxyethyl cellulose (HEC) and xanthan gum were the two polymers used in this study. Both of these fluids find wide application in drilling, completion, and workover fluids. Initial studies were carried out with polymer concentrations of one and two pound per barrel (0.29 and 0.57% by weight respectively). Bentonite, rev dust, and calcium carbonate were used in the concentration range of one to twenty pounds per barrel (0.29 to 5.8% by weight) for the filter cake material. Two different experimental protocols were used in the study. The first experimental protocol consisted of slurrying the solid material in brine, filtering a known amount of the slurry, flowing a clear brine through to establish the permeability, and then flowing a known amount of polymer solution through. The polymer solution effluent from the cell was collected in three different segments. The rheology of each segment was then compared to the rheology of the initial polymer solution. The second protocol consisted of slurrying the solid material directly into the polymer solution and filtering the slurry in the filter press cell. Again, samples were taken and the rheology compared with the rheology of the initial polymer solution.
Since the paper by Cleary and Fonesca in 1992, there have been several attempts to determine if convection is an important factor in proppant placement. Papers by Clark and Courington, Clark and Zhu, and Barree and Conway have provided important clues, but the primary question remains unanswered. To address these questions, we have returned to the question of scaling in models. As mentioned in JPT paper (March 1995) by Clark and Zhu, scaling in a slot-flow model is difficult because each of the possible scaling factors (Reynolds number, velocity, shear rate and pressure drop) have a different dependence on width. Because of this, our initial laboratory model was scaled on shear rate and therefore flowing viscosity. Further examination of the problem lead us to believe that the ratio of the forces available to push the fluid in the horizontal and vertical directions is extremely important in determining whether or not convection is observed. This paper will discuss the development of two dimensionless groups that can be used to predict convection and the experimental evidence that validate these dimensionless group.
Hydraulic fracturing is used as a primary stimulation technique for oil and gas wells. During a fracturing treatment, fluids are pumped under pressure through perforations in the pipe and into the formation. At some point the formation fails and the resulting crack is usually vertical and normally propagates away from the wellbore as two cracks 180 apart. A propping agent, such as sand, is pumped with the fluid to hold the crack open after the fracturing treatment is completed. When discussing fractures, the literature usually only deals with one wing of the fracture. A schematic of one wing of a fracture is shown in Figure (1).
Often the fracture is higher than the producing interval. When the fracture height is much higher than the perforated interval (see Figure (1)), the flow into the fracture can be classified as flow into a slot from a point source. In 1992, Cleary and Fonseca postulated that, in point-source fractures, gravity driven motion of the slurry, which they termed convection, will dominate Stokes type settling in the placement of the propping agent (Figure (2)). This is important because the placement of proppant within the productive interval determines, in part, the amount of production increase.
Unfortunately, while the speculation by Cleary and Fonseca was not supported by creditable experimental evidence, it was accepted almost without question by the industry. Since the concept of convection was proposed by Cleary and Fonseca, there have been a number of papers published on the subject. Clark and Courington published some initial results from a small slot-flow model. This work was followed by a more extensive study by Clark an Zhu and Barree and Conway.
Methane released to the atmosphere during underground coal mining operations is a greenhouse gas and wastes a valuable energy resource. Coal mining in the United States released an estimated 190 to 300 billion cubic feet (Bcf) of methane into the atmosphere in 1990. Based on the current trend of increasing coal production and the mining of deeper, methane-rich coal deposits, methane emissions from coal mines have been forecast to be 260 to 450 Bcf by 2010. Because of inadequate methane capture technology, less than 5 percent of methane released during coal mining is currently recovered for use. New initiatives for coalbed methane will increase its recovery, thus providing important environmental and safety benefits while enhancing the worldwide natural gas supply. This investigation determined the feasibility for installing a 200 kW phosphoric acid fuel cell at a large underground coal mine located in the Black Warrior Basin of Alabama. Assurance of supply, variation of coalbed methane quality, and economic feasibility were studied. The fuel cell can be operated directly from variable-quality coalbed methane produced from underground mining. Waste heat from the fuel cell can be used ill the mine's coal dryer, allowing a portion of the coal normally consumed in the dryer to be sold. Excess electric power, if available, can be sold to the public utility grid. An energy cost of approximately $0.05/kWh is necessary for the direct generation of electric power from a coalbed methane/fuel cell system to be competitive.
Methane released to the atmosphere during coal milling operations is believed to contribute to global warming and represents a waste of a valuable energy resource. Coal mining in the United States released an estimated 190 to 300 billion cubic feet (Bcf) of methane into the atmosphere in 1990. Based on the current trend of increasing coal production and the mining of deeper, methane-rich coal deposits, methane emissions from coal mines have been forecast to be 260 to 450 Bcf by 2010. Largely because of inadequate methane capture technology, less than 5 percent of methane released during coal mining is currently recovered for use. Improved design and technology to lower the costs of methane recovery could make it economically viable in many more mines, thus providing important environmental and safety benefits while enhancing the nation's natural gas supply.
Atmospheric concentrations of methane have doubled over the past two centuries and continue to increase. The Clinton Administration, recognizing the potential environmental risks of methane emissions, has developed the Climate Change Action Plan to control the growth of greenhouse gases in the atmosphere. The initial Plan looks for voluntary participation by the mining industry for increased methane capture. Should the voluntary actions be inadequate, future environmental initiatives will probably require the recovery of methane from coal mines, even though the technology to economically recover methane from coal mines has yet to be demonstrated for most mining situations.
This study investigated the feasibility of operating a phosphoric acid fuel cell power plant on variable-quality coalbed methane. This area of fuel cell power plant operation must be investigated because its application is far-reaching.
Carlson, E.S. (The University of Alabama) | Venkataraman, M. (The University of Alabama) | Clark, P.E. (The University of Alabama) | Sifferman, T.R. (Kelco, A Unit of Monsanto Company) | Coffey, M.D. (Kelco, A Unit of Monsanto Company) | Seheult, J.M. (Kelco, A Unit of Monsanto Company)
SPE 35227 Predicting the Fluid Loss of Drilling, Workover, and Fracturing Fluids into a Formation With and Without Filter Cake E.S. Carlson, SPE, M. Venkataraman, P.E. Clark, SPE, The University of Alabama, T.R. Sifferman, SPE, M.D. Coffey, SPE, J.M. Seheult, Kelco, A Unit of Monsanto Company Copyright 1996, Society of Petroleum Engineers, Inc.
An evaluation of the tests described in the American Petroleum Institute's Recommended Practice "Standard Procedure for Testing Drilling Fluids" would probably lead to the conclusion that the control of fluid loss during drilling or completion operations requires the use of a wall-building fluid. As we will show in this paper, this is not a valid conclusion because power-law fluids can be very effective for invasion control. The lack of a standard test for the invasion characteristics of a power-law fluid is understandable, because the invasion behavior for these fluids depends on both fluid and formation properties.
In this paper, we describe the theory of non-Newtonian fluid invasion from a wellbore to a formation, and discuss a computer model that we developed which is based on this theory. We present computational results which validate the model against analytical and experimental results. Using average parameters that were determined from experiments, we show that formation invasion can be effectively controlled using power-law fluids. We also show that the power-law fluid characteristics which lead to good invasion control do not necessarily lead to long-term restrictions to well productivity. Theory We have searched exhaustively to find invasion models which are comparable to the those presented in the following sections. Many models exist which describe invasion characteristics of wall-building fluids. There are papers which discuss the flow of power-law fluids through linear cores, and other papers which discuss transient pressure behavior of power-law fluids in a reservoir. However, we have not found any which rigorously evaluate the invasion behaviors of power-law fluids. Flow of Non-Newtonian Fluids in Porous Media Unlike Newtonian fluids, which exhibit a constant apparent viscosity, general non-Newtonian fluids have an apparent viscosity which depends on the shear rate, and the shear rate depends on the fluid velocity. For power-law fluids, the apparent viscosity can be given by
(1) where app is the apparent viscosity in cp, n is the flow behavior index, K is the consistency index in dyne.sn/cm2, and is the shear rate in s-1. For a given power-law fluid, it is a routine matter to measure n and K. When a rotational viscometer is used, shear stress is measured as a function of rotational speed. The shear rate is directly proportional to the rotational speed, and the apparent viscosity is the ratio of shear stress to the corresponding shear rate.
Clark, Peter E. (The University of Alabama)
Drilling fluids are, among other things, expected to transport cuttings and control fluid loss. The rheology of drilling fluids plays an important roll in both of these aspects of drilling fluid performance. A number of years ago the American Petroleum Institute established a set of standards for evaluating the rheology of drilling fluids. While drilling fluid technology has evolved and drilling fluids have become more rheologically complex, the standards have not changed sufficiently to adequately characterize the new generation of drilling fluids.
The American Petroleum Institute (API) has established a set of standards for the rheological characterization of drilling fluids, API BUL 13D. A second edition was published in 1985 and the third edition is currently in the last stages of the publication process. API 13D covers everything from basic rheological concepts to data acquisition and analysis. It has a good discussion of non-Newtonian fluid models but this discussion does not include adequate coverage of fluid- models that describe fluids which exhibit Newtonian behavior at low shear rates. For many years, before the advent of low-solids drilling fluids, the models covered in API 13D were adequate. Environmental and operational considerations have encouraged a gradual shift from traditional drilling fluids to low-solids muds that contain polymers to provide the desirable properties. Changing to polymer-based fluids has brought about changes in the mechanisms for viscosity development and fluid-loss control. These fluids are not adequately characterized by the tests outlined in API 13D.
When sheared, a typical non-Newtonian fluid will exhibit flow behavior similar to that shown in Figure 1. The fluid first gives a Newtonian response (lower Newtonian region) to the shear rate and then transitions into a power law region. When the shear rate gets high enough a second transition occurs to Newtonian behavior (upper Newtonian region). Traditionally in the oilfield, measurements are made in what is thought to be the power law region. As we will see, measurements made with the standard six speed instrument do not always provide points within the power-law region. Both the upper and lower Newtonian regions, typically, have been ignored.
Fuzzy regression provides a means for fitting data when the relationship between the independent and dependent variables is vague, or data are imprecise, or the amount of data is insufficient. In this paper, we use it to determine the three parameters of the Archie equation from core resistivity measurements. First, we outline the methodology of fuzzy regression analysis. Next, we show the minimization of a fuzzy objective function by making use of the simplex method described in the previous paper. Last, we illustrate the approach with the same example used in the previous paper.
The Nelder-and-Mead simplex method is used to obtain optimal sets of Archie parameters (m, n, a) from resistivity measurements on core samples. This derivative-free optimization method, despite being a local search technique, avoids trapping by minor optima. We have found that the method is very effective, highly efficaceous, and easily implemented on a PC. The agreement between the results obtained from this method and those from the nonlinear least-squares approach is remarkable.
We present a simple, fast, analytical expression which can be used to estimate the reservoir pressure as a function of gas saturation, for gas saturations between zero and the critical gas saturation. Use of the relation also makes it extremely easy to assess the local recovery factor as a function of pressure from the bubble point down to the pressure at which the critical gas saturation is reached. We hope that the application of this method will reduce the likelihood that operators will let the average pressures of their oil reservoirs drop to the point where significant quantities of free gas flow.