With the increase in average lateral length for horizontal wells comes increased challenges for reaching total depth (TD) with the production casing. Any production interval left un-cased will not contribute to initial or ultimate production or be booked as reserves, which can have a major detrimental impact on the financials of these wells. ALTISS Technologies has designed a patent pending aluminum casing concept to facilitate the installation of long cased laterals, and assist with landing casing at the total depth. Due to its low density and low modulus of elasticity, the aluminum casing is about half the buoyed weight and twice as flexible as comparable steel casing. These physical properties help the aluminum casing lighten the toe of the casing string and navigate through micro doglegs and tortuous wellbores. The aluminum casing was designed with a focus on torque and drag reduction, to be used in limited quantities to maximize the benefits and ensure that casing reaches total depth. Analysis showed that 4,000 pounds of hook load could be added, without casing rotation, with as little as 160 feet of aluminum casing installed, in some cases. To ensure proper threaded connections with the low modulus aluminum, ALTISS designed its own 5 ½" premium threaded connection, which exceeded 56,000 ft.-lbs. yield torque in testing. Multiple aluminum tubular specimens were collapsed in a laboratory setting to validate equations which are not covered by API calculations, nor conventional closed form solutions (e.g. Timoshenko, Tamano). An experimental nano-coating is currently being evaluated that will protect the aluminum from potential forms of corrosion, including galvanic reactions and acid programs. The advantages of installing aluminum casing may allow for eliminating expensive premium threaded connections needed for rotating casing, or alternatives such as floating casing. Ensuring the lateral is 100% cased improves initial production, allowable booked reserves, and ultimate hydrocarbon recovery of the well.

Erosion arising from sand production is recognized as a significant problem in the oil and gas industry, which can a potential danger for operators and a cause for production downtime. In many offshore production systems, it is crucial to determine which well is producing sand so that preventive measures can be applied to minimize sand production. One type of sand detection equipment that is often used by oil and gas companies is an electrical resistance (ER) probe. ER probes are effective monitoring real-time "metal loss". But, there are many flow conditions for which sand may not be impacting and/or eroding these probes. Temperature changes can also obscure ER probe measurements. In this study, experiments were conducted mainly on a large scale multiphase flow loop utilizing 3-inch and 4-inch test sections under gas dominant low liquid loading conditions. The effects of superficial gas velocity, superficial liquid velocity, sand size, pipe size and flow orientation on erosion were also examined. Additionally, acoustic sand monitor was also used on the flow loop and the results are compared with ER probe data. A model that is developed for temperature compensation of ER probes shows significant promise for improving ER probe data for situations where temperature of the flowing fluid changes significantly. Furtheremore, understanding erosion rates that are measured by ER probes can help engineers determine the appropriate production rate in the field and initiate inspection and operation plans to ensure safety and continuous production.

Abstract In this study, two-phase flow pressure prediction correlations and mechanistic models for pipelines commonly used in petroleum industry are evaluated against experimental data. Downward two-phase flow occurs in hilly terrain pipelines, in steam injection wells, as well as in offshore oil and gas production systems. During pipeline design and simulation, experimental data are usually unavailable to calibrate against correlations and models. Sometimes it is difficult to determine which correlation or model to use in predicting pressure gradient in inclined downward flow since there are very a few correlations and models were developed specifically for downward pipe flow. Experimental data used in this study are from a published paper (Kokal and Stanislav, 1989). Experimental data were gathered from 1-inch, 2-inch and 3-inch pipes with seven inclination angles. Oil and air were used as testing fluids. During the experiment, superficial liquid velocities range from 1.2 to 10 ft/s and superficial gas velocities range from 0.76 to 85 ft/s. The experimental results were plotted as pressure gradient vs. superficial gas velocity for each superficial liquid velocity. Beggs-Brill, Dukler-Eaton-Flanigan, Dukler-Flanigan, Dukler, Eaton, Eaton-Flanigan correlations and Xiao mechanistic model are evaluated in this study. The results of this study can be used as guidelines in choosing two-phase flow pressure prediction correlations and models in designing and analyzing downward two-phase flow pipelines. Introduction Downward two-phase pipe flow is a common occurrence in oil and gas production and transportation. Although there are many pipeline correlations and mechanistic models around, during pipeline design and simulation, it is often difficult to determine which correlation or mechanistic model to use. Correlations and mechanistic models evaluated in this study include Beggs-Brill (BB), Dukler-Eaton-Flanigan (DEF), Dukler-Flanigan (DF), Dukler (D), Eaton (E), Eaton-Flanigan (EF) and Xiao mechanistic (Xiao). Below is a brief description of the correlations and Xiao Mechanistic model. The Beggs-Brill correlation was developed from experimental data obtained in a small scale test facility. The facility consisted of 1-inch and 1.5-inch sections of acrylic pipe 90 ft long. Fluids used were air and water. The correlations were developed from 584 measured tests for all inclination angles (Brill and Beggs, 1991). The Eaton correlation was developed from experimental data obtained from a flow system consisting of 2-inch and 4-inch horizontal lines. Correlations were for liquid holdup and two-phase friction factor (Brill and Beggs, 1991). The Dukler correlation was based on similarity analysis and the friction factor and liquid hold up correlations were developed from field data (Brill and Beggs, 1991). The Eaton-Flanigan, Dukler-Flanigan and Dukler-Eaton-Flanigan correlations used the Flanigan corrected correlation, where elevation term in the total pressure gradient is neglected for down hill flow (Brill and Beggs, 1991). Eaton-Flanigan uses Eaton correlation with elevation term neglected, Dukler-Flanigan uses Dukler correlation with elevation term neglected, and Dukler-Eaton-Flanigan uses Dukler correlation for friction calculation, Eaton correlation for liquid holdup calculation and elevation term is neglected (Pipesoft-2TM Manual 2, 2007). The Xiao model is a comprehensive mechanistic model developed for gas-liquid two-phase flow in horizontal and near horizontal pipelines. It has been evaluated against a data bank that includes field data culled from the A. G. A. database, and laboratory data published in the literature (Xiao et al., 1990).

Abstract Cement bond quality is imperative for all phases in the life of a well. Achieving a superior cement bond can be an engineering challenge in areas with naturally fractured formations. Often there is a driving force to lose the cement slurry to the fractures or for the slurry to be contaminated by formation fluid flowing into the wellbore from the fractures. Failure to effectively isolate these zones can be extremely costly over the life of the well. An inadequate cement bond can result in interzonal gas and liquids migration within the annulus, negatively impacting the recovery of hydrocarbons and increasing downhole scaling and corrosion tendencies. In severe cases, subterranean fluids can flow along the annulus all the way to the surface of the well, resulting in environmental contamination and expensive remediation. This paper addresses how adjustments to pre-flushes and spacers have improved cement bond quality in the Appalachian basin. When drilling in the Appalachian basin, encountering hard sandstone, fractured shale, and coals with low pore pressure gradients is very common. The fractured shales and coals may present problems when cementing the well. These problems include cement dehydration due to excessive fluid loss or formation "breakdown," in which whole cement slurry is lost to a created hydraulic fracture. When this situation is encountered, it can be difficult to achieve proper cement tops and cement bond quality can be poor. Field data was collected from Gilmer County, West Virginia. In the study area, the wells were drilled to the Alexander formation with compressed air. Cement jobs were historically pumped with the following schedule: gelled water, cement slurry and displacement. A re-engineered pump schedule now includes a dual chemical-spacer system ahead of the cement slurry. The leading spacer was a mixed cleaner/surfactant solution, and the trailing spacer was a filtrate-reduction solution that also enhances cement adhesion to pipe and formation. Approximately five days following the completion of both cement jobs, cement bond logs (CBL) were run on the wells and the results of each were compared. As evidenced by the comparative analysis of the CBLs, the adjustment in the pre-flush/spacer design resulted in a marked improvement in the quality of the cement bond. These results are documented in the paper. The resulting impact of the modified design on well completion and operating costs are also reviewed. Mitigation of any environmental risks are quantified. Introduction In the Appalachian basin, the total depth of most wells range between 2,000 to 7,000 feet and are drilled via means of " air drilling," also referred to as " dusting". Air drilling is a technique whereby gases (typically compressed air or nitrogen) are used to cool the drill bit and lift cuttings out of the wellbore. 1,2 Using compressed air is most common in the Appalachian basin. The main advantages of air drilling are: It usually is much faster than drilling with liquids it may eliminate lost circulation problems associated with dense liquid-based drilling fluids. Air drilling also allows for continuous well testing or formation-fluid sampling while drilling and minimizes formation damage. The disadvantages of air drilling are the inability to control formation fluids or contain sloughing shales. Thus, its application is limited to consolidated "hard rock" applications, where there is little to no fluid influx or hole stability issues.

Abstract A hydrodynamic model for predicting the flow of natural gas and condensate in transmission pipelines has been developed. This steady state model was used to study the temperature profile along a transmission pipeline. The model is based on formulating the problem in terms of mass, momentum, and energy balance equations. Thermodynamic properties are determined using flash and thermo-physical properties calculators based on a Volume Translated Peng-Robenson EOS (VTPREOS). This new model will provide gas transmission engineers with a versatile tool for modeling multiphase flow in pipelines. It will also provide approximations to the parameters of most importance to them specifically, the impact of temperature and terrain effects on liquid dropout. Liquid formation is a major concern for transmission companies due to the significant decrease in gas flow capacity, inaccuracy in metering, and potential damage to instrumentation and equipment. This model simply tells the field engineer where and how much liquid will form. This information is valuable for locating and sizing liquid collection tanks, and in the design of a cost effective pigging schedule. The results of the systematic numerical studies showed that the temperature of the gas decreased from the inlet condition to that of the surrounding temperature within 3 miles of the inlet. In addition a temperature rise of up to 5 degrees Fahrenheit was observed when an undulating terrain was simulated (in downhill flow). Introduction Multiphase flow phenomenon occurs in several hydrocarbon production systems. This phenomenon poses some serious problems for the design and operation engineers and personnel. The frictional pressure losses necessary to size pipes become much more difficult to calculate. In addition operational difficulties arise. Multiphase flow significantly reduces the volumetric capacity of pipelines and necessitates installation of separation stations and implementation of expensive pigging schedules. Basically the design engineer needs to know the size pipe to be used which is obviously related to the expected pressure drop. In addition it is necessary to estimate the liquid dropout location and quantity in order to design and place efficient separation units. The operator of the pipeline needs to establish an efficient pigging schedule in order to minimize operating cost and therefore maximize profit. In addition, transmission companies periodically perform optimization studies aimed at improving the overall technical and economic soundness of there operations. The aforementioned requirements make it a necessity to have tools for multiphase flow analyses. Traditionally these analyses have been performed using empirical correlations. Among the more popular of these methods are the Beggs and Brill [1973] method, and the Aziz et al. [1972] method. Brill and Mukherjee [1999] present a detailed discussion of these methods. In order to supplement these methods, hydrodynamic modeling has been used at Penn State [Adewumi et al, 1993] for the passed twenty years to provide a more detailed and theoretically sound analysis of multiphase flow phenomenon of gas and condensate flow. Successive development was made by Vincent [1988], Mucharam [1990], Boriyantoro [1994], Martinez [1994], Carrillo [1999], Antonini [2000], Ayala [2001], and Eltohami [2003]. The present model incorporates several contributions to the multiphase flow research. First a more accurate PVT model is used in order to better predict density of the liquid. Second, the energy equation is coupled to the mass and momentum equations which is a more theoretically sound approach compared to the normal approach of using a correlation to determine the temperature distribution. The purpose of this paper is to address in details temperature variations in gas / condensate flow.

Abstract The use of mud motors and other tools to accomplish forward motion of the bit in extended reach and horizontal wells allows avoiding large amounts ortorque caused by rotation of the whole drill string. The forward motion of the drill string, however, is resisted by excessive amount of friction. In the presence of large compressive axial loads. the drill pipe or coiled tubing tends to buckle into a helix in horizontal boreholes. This will cause addition;al frictional drag resisting the transmission of slack-off force to the bit. As the magnitude of the frictional drag increases, a buckled pipe can become locked-up' making it almost impossible to drill further. In case of packers, the frictional drag may inhibit the transmission of set-up load to the packer. A prior knowledge of the magnitude of frictional drag for a given axial force and radial clearance can help avoid lock-up conditions and costly failure of the tubular. In tliis study, we present a neural network model for the prediction of frictional drag and slack-off load transmission in horizontal wells. Several neural networks with different architecture were designed and tested to obtain the most accurate prediction of these parameters. After cross-validation of the neural network, a two-hidden layer model was chosen for simultaneous prediction of frictional drag and slack-off load transmission. P. 259

Abstract Drilling penetration rate can be increased when drilling a horizontal well by rotating the drill string, which helps to overcome the drag and apply the bit weight. However, drill-pipe fatigue may become a problem for rotating the drill string in the build section of the wellbore especially in drilling medium/short-radius horizontal wells, where the drill pipe experiences a large bending. This paper presents an analysis of drill-pipe bending and fatigue in rotary drilling horizontal wells. The wellbore curvature, axial compressive load, drill-pipe weight, and drill-pipe tube contact to the wellbore wall are considered. New equations are derived to improve the prediction of the maximum drill-pipe bending stress and drill-pipe fatigue. The results show that drill-pipe tube contact to the wellbore wall, which happens under large axial loads, may help reduce the maximum bending stress, and therefore, benefit the fatigue control. The drill-pipe weight usually increases the bending stress and needs to be considered to accurately predict the fatigue damage. Introduction Drill-pipe fatigue was first studied for drill-pipe rotating in a dogleg wellbore section under axial tensile load. The recent application of rotary drilling medium/short-radius horizontal wells involves the situation where drill pipe rotates in the build section of the wellbore under axial compressive load. The drill pipe is first bent along the build section of the wellbore, and then the axial compressive load and drill-pipe weight push further bending or deflection between the tool joints. The maximum bending stress in the drill pipe could be much larger than that calculated by assuming the drill pipe bent with the wellbore curvature. Maximum Bending Stress Fig. 1 shows the drill-pipe bending/deflection development in a build section as the axial compressive load increases. Under a small axial compressive load, the maximum bending curvature is located at the midpoint of one joint of drill pipe, and there is no drill-pipe tube contact to the wellbore wall (Fig. 1a). As the axial compressive load increases, the middle of the drill-pipe tube starts to contact the wellbore wall ("point" contact, Fig. 1b). Further increase of axial compressive load increases the contact length in the middle part of the drill-pipe ("arc" contact, Fig. 1c). The maximum bending curvature moves to somewhere in the uncontact portion after the tube contact occurs. Drill pipe under axial compressive load is considered in this paper for rotating through the build section of the wellbore in drilling a medium/short-radius horizontal well. However, similar equations for axial tensile load condition can be derived by the same approach. The tubular bending differential equation for the drill pipe in the build section of the wellbore and under axial compressive load is (Fig. 2): (1) where Based on the fact that the tool joints are stiffer than the drillpipe tube and follow the wellbore trajectory, the following boundary conditions exist for drill-pipe bending: (2) (3) The general solution of the above differential equation under these boundary conditions is: (4) P. 195

Abstract Pressure drop prediction in pipes is an old petroleum engineering problem. There is a long history of attempts to develop empirical correlations to predict the pressure drop in pipes. Some of these attempts have produced correlations that provide good prediction in some cases. However, their general applicability is questionable. Correlations that address only a specific class of problems exist. These types of correlation usually perform better than those which attempt to meet the need of a variety of problems. Usually, the higher the number of variables in the model the lesser the reliability and general applicability of the correlations. This is the result of using methodologies such as conventional regression analysis. In such methodologies, the chances of correctly and completely capturing the relationship between variables decreases as the number of variables increases. Many parameters could be involved in these types of problems, such as gas-oil ratios in two phase systems, water flow in three phase systems, and inclination angles of the pipe, to name a few. In this paper, the authors introduce a new methodology for developing prediction models for pipes. This methodology, which l)as been named Virtual Measurement in Pipes (VMP), incorporates the cutting edge of information technology, artificial neural networks (ANN), to address the development of tools to predict pressure drops in pipes and optimum design of pipelines under a variety of circumstances. The fundamental problem with conventional approaches resides in the inherent sequential and point wise (as opposed to parallel and distributed) information processing methods used in development of such correlations. Because of this short coming, conventional methodologies are unable to address, define, or unravel the highly complex relationships between many variables involved in the process. In this paper, artificial neural networks are used to develop a Virtual Measurement Tool to survey flowing bottom hole pressure in multi-phase systems using information such as oil, gas and water flow rites, temperature, oil and gas gravity, pipe length, surface pressure, and inclination angles of the pipe. The developed Virtual Measurement Tool has been applied to the published field data for flowing BHP predictions. VMP's predictions are compared to existing methods and the enhancement is clearly demonstrated. The developed VMP tool can be applied to wellbore hydraulic problems. It can address three-phase (oil, water, and gas) flow in well bores. This tool applies to a variety of wells, including vertical wells and those with various degrees of inclinations. Introduction Flow of oil and gas under multiphase conditions occur in different phases of production in a field. Many installations such as tubing, pipelines, separators, treaters, and heat exchangers are of everyday occurrence. Optimum pipe size is an important factor that determines the feasibility of the operations described. Among different components, the production tubing plays the utmost importance in maximizing the reservoir energy in naturally flowing and artificial lift wells. The problem of interest here is the ability to predict the relationship between fluid properties and rates, and the pressure drops under varying physical conditions like pipe size and diameter. The pressure drop prediction in a multiphase flow system is a very complicated problem. In general a total energy balance between two ends of the pipe under investigation is used to determine the pressure drop and flow rates. Resulting steady state equations are coupled with experimental data for multiphase fluid properties yielding a semi-empirical approach. Due to the many flow patterns with different geometry and mechanics, the several forces acting on the flow system can vary in magnitude. The three components of the pressure drop equation deals with elevation, friction, and acceleration of fluid in the tubing. Adding to the difficulty of the problem is the description of fluid properties such as density and viscosity, frictional loss determination for the multiphase mixture, and the calculation of phase velocities. P. 15

Abstract The prediction of liquid holdup and multiphase flow regimes present in a well or pipeline is very important to the petroleum industry. Liquid holdup, defined as the fraction of pipe occupied by liquid, and flow regimes must be predicted to design separation equipment and slug catchers in pipeline operations properly. It is also important when designing gas storage fields in depleted oil reservoirs. A new methodology was developed to model multiphase flow conditions for pipelines and wellbores using only known surface data, This methodology, which has been named Virtual Measurement in Pipes (VMP), incorporates an innovative use of information technology and computational intelligence, to address the development of tools for the engineer to use in the design process for a variety of conditions. Artificial neural networks (ANN) were used to develop a Virtual Measurement Tool to survey the liquid holdup and flow regimes in nonspecific multiphase flow systems using readily available data. The VMP methodology was tested for validity by comparing virtually measured values with published measurements, As a result, the method proved to be an accurate virtual measuring tool to predict liquid holdup and flow regimes in multiphase flowing pipelines and wellbores, The VMP methodology also demonstrated an enhancement to existing industry recognized correlations. Introduction Flow of gas and liquid occurs frequently in pipelines and wellbores where the accurate calculation of a pressure drop is of considerable interest to the petroleum industry. Similar conditions exist in the chemical and nuclear industries where two-phase mixtures coexist. In the petroleum sector, gas-liquid mixtures are transported over long distances in a common line under large pressure drops which influence the design of the system. Other important areas of application can be cited as gas lift operations and wellhead gathering systems. Practically all oilwell production design involves evaluation of flow lines under two-phase flow conditions, However, the uncertainties in flow regime determination greatly affect the pressure drop predictions. A method is desired for accurate calculation of pressure losses. Pressure losses in two-phase, gas-liquid flow are different from single-phase flow, An interface exits in most cases and gas slips past the liquid with a surface of varying degrees of roughness depending on the flow pattern. Each phase flows through a smaller area than if it flows alone causing high pressure losses when compared to single-phase flow, Additionally, this segregated flow changes at any point along the flow path during the fluctuating flows. Under the conditions of distributed phases, prediction of fluid mixture properties like density and viscosity becomes a challenge for the design engineer. The density and viscosity along with the velocity are important terms in the determination of pressure losses in any pipe system. Several correlations are proposed to define the holdup and flow patterns for horizontal, vertical, and inclined pipes. In general, these correlations are based on experimental work conducted under specific conditions such as a constant pipe diameter. The application of artificial neural networks in the petroleum industry is recent and its potential is not fully investigated. This technology is applicable in many areas where an existing pattern is not obvious to the naked eye of the researcher as is the case of log evaluations. Complex patterns and relationships in data, such as holdup and flow pattern, can be established through an artificial neural network. Approach A new methodology is introduced to investigate the holdup and flow pattern determination problem in pipes under multiphase conditions. This approach uses the measured data to determine the relationship between input and output parameters, The Virtual Measurement in Pipes (VMP) tool utilizes the pattern recognition capabilities of an artificial neural network. P. 21

Abstract This paper presents results from experimental data for sinusoidal buckling of tubulars in vertical wells and discusses some analytical solutions presented in the literature. An experimental apparatus 55 feet long was used in the tests. Several tests have been conducted and the results are presented and analyzed. The following aspects of sinusoidal buckling were observed during the tests: critical sinusoidal buckling force, contact point between pipe and wellbore, further buckling modes, effect of friction in the post buckling behavior. Introduction An ideal (weightless) pipe, subjected to an axial force F as shown in Fig. 1, will buckle in an approximately sinusoidal shape provided that is satisfied the following inequality (1) where: L: Length of the string B: Bending stiffness Since a weightless pipe does not exist in practice, the buckled shape will not be a true sinusoidal but rather of the shape shown in Fig. 2. REVIEW OF THE LITERATURE The first rigorous treatment of drill string stability was presented by Lubinski in 1950. In that pioneer work an analysis of two dimensional buckling of pipes in vertical wells and its effects on bit inclination, shape of the string, wall contact force, bending moments, etc., was presented and thoroughly discussed. Using power series Lubinski has solved the differential equation governing the instability problem. His solution, given by Eq. (53) in Ref. 2, is not straightforward, but gives very precise results. As an approximation, for practical purposes, Lubinski proposed the critical force for first mode of buckling as: (2) where m is the length, in feet, of one dimensionless unit (3) Equation (2) is in fact the solution for a string with a length equivalent to 7.94 dimensionless units. Although Eq. (2) gives a very good approximation, it will be shown later that, for strings with length greater than 7.94 dimensionless units, the critical force is less than that predicted by Eq. (2). To determine the exact critical force one must find the result solving Eq. (53) from Ref. 2. P. 77^

SPE Members Abstract Multiphase flow conditions occur in a wide range of engineering applications in the petroleum, chemical, and nuclear industries. The design of production systems involving different fluids requires an accurate prediction of the pressure loss. Existing methods rely on the prediction of flow patterns based on observed field and experimental data. However the patterns are not applicable to all conditions and the predicted pressure drops deviate from actual observations. This paper describes the new model developed to predict pressure drop for vertical, inclined, and horizontal pipes and wellbores. The model is composed of fluid property correlation, flow pattern prediction, and pressure drop determinations. The model performance is evaluated using published data, The model predictions are also compared with a commercially available model The overall performance of the model is in good agreement with data. In comparison with the published data, the model predictions resulted in the least average error. Introduction Prediction of pressure losses in multiphase pipe flow is a concern to different professionals such as nuclear, chemical, and petroleum engineers. Although the nature of fluids encountered in each discipline is different, the principles and physical laws that apply to multiphase flow are similar. In this paper the focus will be the application of methods for oil and gas flow in pipes. In early days of oil and gas production, the importance of pressure drop prediction in a pipe has been recognized and different methods proposed by several investigators to predict the pressure loss. Although the methods were based on empirical correlations from experimental studies, the results were generally satisfactory for the conditions under which each model was developed. When flow conditions were different from the cases studied, the pressure drop calculations were not reliable. In general a multi-phase pressure drop model can provide a good tool to design wellbore and pipelines. The future flow conditions can be studied to determine the feasibility of an operation. The major areas of interest to Petroleum Engineers are the construction of lift curves, tubing size selection, artificial lift completions, and surface gathering lines. P. 87^

Abstract An experimental study was carried out to investigate the performance of new cement additives in controlling or eliminating gas migration through cemented wellbore annulus. The shrinkage behavior of the proposed cement slurries was obtained as a function of time and applied pressure at constant bottom hole temperature. Ultra-sonic measurements were correlated with the strength and bulk density of the cement. These measurements were used to screen out cement slurries for further testing in a cement simulation unit. This unit consists of a 7" casing pipe placed inside a 10" controlled temperature water bath. The experimental unit was 6 ft long and was used to simulate borehole pressure and temperature conditions. The borehole was modeled by drilling a 2" diameter hole through 2.5 ft long cylindrical core samples. A large number of additives was tested to evaluate their effects on the cement volume fluctuations which are the primary causes of gas migration. A thorough procedure was followed to evaluate the effectiveness of all tested additives in controlling or eliminating the creation of micro-fractures during cement setting under borehole pressure and temperature conditions. The results obtained from this extensive experimental study show that the use of the proposed additives decrease significantly the cement volume fluctuations during cement setting. The new cement additives proposed in this study reduce the contraction-expansion mechanism effects during cement slurry setting, thus minimizing and controlling the creation of micro-fracture. Introduction Gas leakage through cemented wellbore annuli or cement plugs is a major problem of concern in many oil wells in the world. There are over 3,000 oil wells in the United States which have exhibited gas leakage problems and are abandoned because of government regulations. Enormous amount of money is spent on squeeze cementing to redeem gas leakage without producing a permanent solution. The danger posed by this problem is not only expensive to control temporarily, but also a menace to the environment. Since 1960 attention has been given to the problem of gas channeling through micro-annulus and microfractures to enhance cementing by reducing gas leakage at the surface or between reservoir formations. The three main reasons for gas channeling through a cemented annulus are (i) the mud cake that remains between cement and the permeable formations provides a weak zone for the passage of the water and gas, resulting to failures in cement jobs, (ii) the inability of cement to hold the high fluid pressure at the period of its initial set which may cause water accumulation, resulting to micro-fracture within the cement body, and (iii) the cement's inability to maintain overbalance pressure on the gas bearing formation, because when the slurry is static (cement is not pumpable) it begins to develop a static gel. Static gel strength provides high resistance to the cement movement and prevents the hydrostatic effect of the cement slurry on the formations. Previous investigators, Carter and Slagle and Keller et al. showed that gas migrates as a result of the physical properties of cement and drilling fluids, and also because of other physical properties such as pipe movement, well parameters and casing centralization. Some other investigators related the gas migration through the micro-fractures and micro-annulus to the cement chemical behavior, whereas others related this to the cement shrinkage and its behavior. P. 101^

SPE Member Abstract Columbia Natural Resources, Inc. and Columbia Gas System Service Corporation, subsidiaries of the Columbia Gas System, and the United States Department of Energy (DOE) have successfully drilled and completed a horizontal well in the Devonian Shale in Martin County, Kentucky. The objective of this co-funded project is to assess the effectiveness and economic feasibility of applying horizontal drilling and stimulation techniques to enhance the production of natural gas from the Devonian Shale. Columbia's well is one of three wells in a DOE program called "Horizontal Wells in the Devonian Shale."Drilling began June 1, 1990 and ended July 7, 1990. The well contains a three-part profile, a conventional vertical section, an profile, a conventional vertical section, an angle building or curved section and finally the horizontal section. The well reached a measured depth (ND) of 6,263 feet, 3,754 feet true vertical depth (TVD) and a horizontal displacement of 2,872 feet was achieved in the desired direction, N12 degrees W. Both air and foam were used as drilling fluids. The vertical section, tangent section between the curves and the horizontal sections of the well, were drilled using conventional rotary drilling methods. Downhole motors were used to build angle in the curved sections. Thirty-five gas shows were detected by the mud logger while drilling; measured flow rates exceeded 1 million cubic feet per day (MMcfd) at TD. Mud and geophysical log information were used to establish discrete completion zones. A 5-1/2" production string equipped with five Payzone Packers and FO Completion Tool Payzone Packers and FO Completion Tool established six completion zones: an openhole/slotted liner section at the bottom; three zones isolated by the external packers with access to the formation through sliding sleeve FO completion tools; and, two zones which were cemented. Overall, this application of horizontal drilling has proven that additional reserves can be developed in the Devonian Shale by its application. The current economics could be greatly improved by developing additional technology. Background The Devonian Shale of the Eastern United States is characterized as an unconventional gas reservoir because of its typically small gas flows. However, this resource contains vast quantities of natural gas estimated at upwards of 2,500 trillion cubic feet (TCF). Depending on gas price, estimates of recoverable gas utilizing conventional technology range from only 20 to 60 TCF. The ability to accelerate and improve ultimate gas recovery from this resource requires the development and application of advanced practices. Successful applications of Horizontal Drilling could not only have a significant economic impact, but could also contribute substantially to United States natural gas reserves. The value of high-angle drilling perpendicular to natural fracture systems for perpendicular to natural fracture systems for maximizing production from fractured reservoirs was recognized early and Columbia Gas System has been testing this theory since the 1950's.Since the drilling of this and several other high-angle or horizontal holes in the Appalachian Basin, technology has improved significantly thus giving the capability to drill highly deviated and lateral holes more economically. P. 315

Abstract This paper describes a method of measurement to be used in completing an open-hole frac procedure. Unlike cased hole work, a gamma ray - CCL log is used in correlation with a steel line measurement (SLM) to supply the completion rig crew with correct depths for placement of completion activities. This assures that the dollars spent for stimulation of the reservoir rock will be used to achieve the greatest results. Introduction Proper depth control in open-hole fracing is Proper depth control in open-hole fracing is crucial to the successful stimulation of the reservoir rock. The correct placement of air notches and establishment of the depth of plugback and frac packer all require precise measurements. In wells that include fairly thin reservoir rocks and multiple zones targeted for treatment, this procedure becomes especially critical; a method procedure becomes especially critical; a method must be devised to tie in accurately to information found on open-hole logs. Open-hole logs may be unusable for accurate depth determination for several reasons. Footage increments in wireline equipment may differ from physical measurements made by the rig crew who work with either a pipe tally, SLM, or combination of both. Additionally, when open-hole logs are run, the zero-point (point from which the log is measured on the surface) is commonly a drill floor or Kelly bushing which may be from two to fourteen feet above the surface casing. However, when the completion rig moves in to start the frac procedure, these reference points are no longer available, and confusion as to whether to add or subtract footage and in what amount may contribute to errors. To lessen the possibility of such errors, a correlation gamma ray - CCL log is run inside a string of tubing (usually the notch pipe) and correlated to its length, preferably by use of a SLM. These measurements are then the known dimensions by which the rig crew must perform its work. Background Open-hole fracing is a completion technique that has been commonly used in upper Devonian oil and gas well completions in the Appalachian Basin. Instead of a string of production casing cemented in the well and perforated to frac, a frac packer on the end of a string of frac pipe is packer on the end of a string of frac pipe is suspended in the hole and utilized to isolate the top of the zone of interest. A fine mesh gravel or coarse sand known as plugback fills the hole beneath the zone and a groove or "notch" is cut directly into the formation at the point that is desired to be fraced. This notch is designed to create a point of weakness in the well bore to initiate or lead the frac. All of these elements aid in the control of the frac, and it is imperative that an accurate measurement system be used to determine their appropriate placement. Unlike a string of cemented casing with perforations placed with the use of a gamma ray - CCL log, after which no other measurements need be made, an openhole procedure requires repeated usage of known depths and the ability to return to them (Figure 1). Experience has shown that logs run in the same well by different wireline companies may differ as to depth of identifiable features by as much as several feet. Similarly, the logger's total depth (LTD) may differ from the driller's total depth (DTD) which is usually measured from either a pipe tally or SLM. P. 273

Abstract Wells drilled into the Trempealeau formation in south central Ohio require adherence to special plans and attention to detail at the price of plans and attention to detail at the price of economic success. This formation is marked by nonconformance, paraffin production, delicate oil-water contact, and a susceptibility to drilling-induced damage. This paper provides guidelines for completion practices that have been based on 30 years of practices that have been based on 30 years of drilling in the Trempealeau formation and presents typical job designs. GEOLOGY The Trempealeau is a dolomitized limestone of the Cambrian Age. Sometimes referred to as the Copper Ridge, the Trempealeau is found throughout most of Ohio. It is located on the western edge of the Appalachian Basin and the eastern flank of the Findley Arch. The Trempealeau is the basal unit of the Knox Group (Fig. 1). It is believed that the Trempealeau was originally deposited as a limestone in a shallow, low energy, marine environment. Dolomitization apparently occurred prior to deposition of the Ordivician Strata, and as a result, the formation is generally a fine to coarsely crystalline, partly sandy dolomite that is light colored with a granular texture. The Trempealeau is marked by the Knox Unconformity (Fig. 2). This uncomformity acted as a path for hydrocarbons that migrated from the path for hydrocarbons that migrated from the Appalachian Basin. The eroded remnant left by the uncomformity serves as a permeable and porous trap and has up to 110 ft of local relief. Hydrocarbon traps are found in the tops of buried hills (Fig. 2). The productive porosity in the Trempealeau is secondary and is caused by dolmitization and dissolution. Average thickness of the Trempealeau is 300 ft, and vugular porosities are as high as 30% in its upper zones. The Trempealeau is subdivided into six zones (A through F). Only the upper two zones, E and F, have the potential for hydrocarbon production. If pre-Ordivician erosion has removed the upper two pre-Ordivician erosion has removed the upper two zones, no commercial production would be expected-even from a structurally high area. Natural fractures are not well documented; however, core observations and stimulation results indicate that a significant network of natural fractures may exist. The possible existence of these natural fractures has been indicated by early water breakthrough in producing wells. FIELD HISTORY The first documented Trempeleau producing well was drilled in 1909 in Seneca County, Ohio. Small, isolated producing pools of Cambrian oil were documented between 1909 and 1961 in west- central Ohio with initial productions of 25 to 100 BOPD with accompanying salt water production. The discovery well that started the modern Trempealeau boom was United Producing Company's Orrie Myers #1, which was drilled in the Canaan Township of Morrow County, Ohio. It was drilled to a depth of 3174 ft, and completed in the Trempealeau zone through perforations at 2908 to 3031 ft. The well, initially flowed 200 BOPD of 39 deg. API gravity oil. P. 223

SPE Members Abstract Air drilling uses air or gas as the circulating medium. Because there are so many variables involved in air or gas drilling no one general method has been developed to predict the appropriate volumetric requirements for field use. In an attempt to alleviate this problem a computational model has been designed and developed which can analyze the pressure drop contributions for the complete air drilling system. This will facilitate the optimization of the air or gas pressure and volume requirements. The model is capable of analyzing the effects of variations in flow rate, sandpipe pressure, cutting size distribution, and loading. Studies conducted using the computational model includes an analysis of several methods for determining pressure drop due to the solids phase. The results from these studies were compared with Industry Field Experience Data. Two of the methods indicated good agreement with the data. Introduction Air is the ultimate low-density drilling fluid which enhances the generation of fractures at the formation and bit interface. This is accomplished because the hydrostatic pressure created by the column of air at the bottom of the hole is less than would be created by conventional mud systems. The use of lower hydrostatic pressure allows the rock at the bit surface to be easily crushed and the chips to explode off the bottom and be introduced into the air stream, thereby increasing the penetration rate. Optimal results and greatest economy from air drilling techniques depend on several factors. Mature competent formations that produce little or no formation fluids provide the best results. Also drilling should be limited to geologic areas where reservoir pore pressures are low or not large enough or prolific enough that dry air dust drilling techniques are rendered inoperative. Air drilling is very useful in minimizing formation damage to potential producing zones. It is clear that there are many economic incentives to develop a method which will accurately determine the standpipe pressures and air flowrates required to lift drilled cuttings up the wellbore annulus. This method should prove useful and accurate for various drilling environments that may be encountered. There are many difficulties in mathematically modelling gas-particle flows. Because of these difficulties studies conducted in the past have made assumptions which simplify the approach but lose accurate predictive capabilities. The primary difficulty which arises is the fact that the friction, hydrostatic effects, and heat flows are not easily described in a two phase environment. This paper presents a computational model which can analyze the behavior of the air-drilling circulation system, and can be used to estimate the minimum flow rates and pump pressure for varying drilling rates. Incorporated in the computational model is an option to consider the effects of velocity and temperature non-equilibrium between the gas and solid phases and the heat flow contribution from the formation, using a combination of momentum,, and energy coupling. This computational model can be applied to any isothermal or non-isothermal one dimensional flow of gas solids suspension. The model offers variations in air flow rate, standpipe pressure, cutting size distribution, loading, and therefore can be used for sizing of surface equipment in the designing stages of an air drilling operation. LITERATURE REVIEW There have been several industry accepted methods developed for predicting volume requirements in air or gas drilling techniques. P. 271^

Abstract The fast paced and hydrostatic-free nature of air drilling presents unique problems when blowouts are encountered. Well control practices for air drilling lag considerably behind techniques applied for fluid drilling. The formation at the surface casing shoe is commonly the weak link during killing operations and any well control plan must protect against shoe breakdown. The technique described below is based on monitoring pressures at the choke manifold to keep pressures at pressures at the choke manifold to keep pressures at the shoe below breakdown pressure. In the field, air drilled well control requires rugged, easy to maintain equipment and a simple well control plan. Introduction Modern well control practices are designed for use in fluid drilled holes. If a standard fluid well control procedure such as shutting in the well after a kick were attempted in an air hole, it could result in an underground blowout. Most well control courses do not deal with air drilling, because it is not common industry practice to air drill into strong wells. Consequently field practices vary widely. However, many wells are air-drilled in the Appalachian basin each year which require killing before the cementing of the production casing. Early Bass Island blowouts are production casing. Early Bass Island blowouts are remembered as costly and dangerous ordeals. Large gas flows from relatively shallow depths can be difficult to control and pose dangers besides fire and injury. If during the killing operation the formation at the surface casing shoe is broken down an underground blowout could occur. An underground blowout is considerably more difficult to control and could result in the contamination of aquifer zones or gas escape at the surface a great distance from the wellbore. Concern over aquifer contamination can be seen in ever increasing oil and gas drilling regulations. Commonly, after a blowout while air drilling, the hole was flooded through the drillstring with a kill fluid and returns vented to the pit through he blooey line. Problems occured when shallow high volume zones were Problems occured when shallow high volume zones were encountered which would blow the kill fluid from the well as fast as it was being pumped in. Heavier kill fluids were then mixed in an attempt in exert greater hydrostatic pressure at TD. Quite often this caused an over balance condition which would result in lost circulation and waste of killing fluids. Another common method was to choke the well back or shut it in and effect a variation of a bullhead kill. The problem with this technique lies in the weakness of the formation at the surface casing shoe. The lowest breakdown pressure in most wells is immediately below the last cemented casing seat. The fracture gradient for shallow formations is variable but can be assumed to be less than 1.0 psi/ft (Harrison, 1985). In naturally fractured Devonian shales lost circulation can occur at pressures less than 1.0 psi/ft. In most cases, the formation at the shoe, not psi/ft. In most cases, the formation at the shoe, not the casing or surface equipment, is the weak link in the killing operation. Although they have not been publicized many shoe failures have occured during publicized many shoe failures have occured during killing operations in the Appalachian Basin. One answer would be to set a longer surface casing string which could allow the well to be shut in without shoe breakdown. Due to the low ratio of blowouts to holes drilled and the prohibitive cost of a longer string the state mandated casing minimums are generally used. Any air-drilled well control plan must therefore take into account the breakdown pressure at the surface casing shoe and this pressure pressure at the surface casing shoe and this pressure cannot be exceeded. In addition, the fluid itself and the choke manifold system should be configured to handle the proposed drilling targets. The surface equipment is more likely to be used if it is simple and easy to rig up. Flanged choke system lines lend themselves better to tear-down and rig up and resist vibration failure. WELL CONTROL THEORY The method of well control, described in this paper, was developed in the field to meet the unique paper, was developed in the field to meet the unique requirements of air drilling. Casing design and an understanding of formation integrity at the casing shoe are the first components in this technique of air drilled well control. The lack of fluid hydrostatic requires a different approach to well killing techniques. This technique involves measuring the volumes of kill fluids pumped and the surface pressures imposed at the choke to prevent casing shoe failure and limit additional influx from the formation. P. 65

Abstract Any object dropped or stuck in a well that interferes with it's normal operations is called a fish and must be removed from the well. The operation of removing these objects is called a fishing job. When we are involved in a fishing job, we simply say "We are fishing". Why or when these terms were first used, no one seems to know, but there are some similarities. We use a long line (the work string). The fish cannot be seen, but we do have to catch it (engage it) before the fish can be pulled out. I cannot think of any better terms, so let's go fishing. Fishing jobs are put into two classifications, open hole and cased hole. When there is no casing in the area of the fish, it is called open hole fishing. When the fish is inside casing, it is called cased hole fishing. There are numerous kinds of fishing jobs. Wash over job, overshot run, spear run, stripping job, jar run, —that's just a few. There are many things that can become a fish - - stuck drill pipe, broken drill pipe, drill collars, bit, bit cones, hand tools dropped in the well, sanded up or mud stuck tubing, packers become stuck, and much more. Wire line broken or stuck in open hole or cased hole can create a bad fishing job. There are many other things that can develop into a fish and many other causes that create a fishing job that haven't been mentioned here. Since there is so many different kinds of fish and fishing jobs, there are many different tools and methods to do the job. Some of the tools are very simple and some are very complex. There are no two fishing jobs alike, yet there are lots of fishing jobs similar. An experienced fishing tool man will draw from the experience he has gained on each job. It is very important on a fishing job for all parties involved to cooperate with each other. It is parties involved to cooperate with each other. It is important for the fishing tool people to obtain all the information concerning the well. That way they can select the right tools and methods to clean the well out as quickly as possible. Introduction Every well will dictate what you can run in it, there are no set rules you can use to do a fishing job. There are guidelines you can use, but most important is to get as much information as possible concerning the well and put together a good plan before starting the job. When running any fishing tools in a well, they should be run at a moderate speed. Most fishing tools are designed to go over and around the fish. For the tools to do this, they have to be larger than the fish. In most cases this makes the tools chase to the hole size, therefore if they are run at a fast speed while going in the hole, they will act as a piston causing excess pressure below them. Quite often, this causes a lost circulation problem or you might hit a tight place in the well that would wedge the tools where place in the well that would wedge the tools where you could not pull out of it. Some care should be taken when pulling out of the hole with most tools and fishing so you do not create a swelling action. Also, to prevent pulling into a tight place such as a keyseat so you cannot go back down.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Introduction The Arab embargo of oil shipments to the United States in 1973 as a result of the United States' support of Israel in the Arab-Israeli Yom Kippur war, and the subsequent formation of OPEC (Organization of Petroleum Exporting Countries), who instituted a worldwide increase in oil prices, triggered a reaction in the Unite States that is still far from settled. The year 1974 was confusing at best—high interest rates, tight money supply, materials shortages and all-out production, rapidly accelerating inflation after price controls, and lifting of the oil embargo—all occurring more or less simultaneously. Then some cooling of economic growth became apparent; real GNP declined for four successive quarters. Consumers, who lost buying power to inflated prices, decreased their purchases. Appliances, textiles, furniture, and housing construction moved into a deep recession. U.S. automotive production for the model year was off 30 percent, and sales curves show no real recovery yet in 1975 despite high-powered promotional campaigns. promotional campaigns. In the early months of 1974, the capital goods market seemed immune to growing recessionary signs. There existed a pent-up demand for increased plant capacity in many sectors after price controls expired. Environmental price controls expired. Environmental considerations had forced the shutdown of many facilities that could not operate profitably, and unprecedented activity began to increase electrical generating capacity and fossil fuels supply. Accelerating escalation rates and lengthening materials lead times continued into September. Then signs of some decline in the rate of those increases began to appear. Nevertheless, in continuing short supply were: steel, forgings, castings, ferroalloys, pig iron, motors, coal, coke, bearings, fasteners, pipe, and pipe fittings. All of these items were needed for energy projects. HISTORY To counteract the implications of U.S. dependence on imported oil, The Federal Energy Administration in its "Project Independence Blueprint" started an all-out domestic energy search. In the U.S., rising oil and gas prices touched off the biggest oilfield rush since the 1950's. It became apparent quickly that the industry was geared to drill more wells than there were pumps, piping, and associated equipment available to bring products to the surface.

This paper was prepared for the Eastern Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Charleston, W. Va., Nov. 4–5, 1971. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Problems encountered in drilling and completing wells to 15,000' and below are reviewed in this paper. Statistical trends in deep well drilling indicate that increasing numbers of such wells will be drilled each year. Problems associated with this activity are similar to those of past shallow drilling. However, these problems are more severe and much more expensive than those in the past. The role of a drilling coordinator, with regard to the development of sound, workable drilling plans, is discussed. A method of well planning is presented that, if used, will reduce the frequency of expensive problems in deep drilling. Many of the recurring problems involved in deep drilling are discussed, as are some of the more recent engineering solutions to these problems. This discussion centers not only on the drilling problems, but on some of the completion problems, but on some of the completion problems as well. One such problem involves problems as well. One such problem involves the attempted completion of wells drilled below depths where commercial production is extremely unlikely to be found. A means of avoiding this problem is also discussed. It is concluded that a great majority of such drilling and completion problems could be eliminated in most cases by better planning, and better trained on-site rig planning, and better trained on-site rig supervisors carrying out the previously agreed upon well plans. Introduction Statistical trends in the drilling of oil and gas wells in the United States indicate that the number of deep wells is increasing and that the yearly average depth of these wells is increasing. There are two primary reasons for these trends. The first reason is the fact that there are fewer good shallow prospects to be drilled, and secondly, a real energy crisis is fast approaching in the United States. To avoid this energy crisis problem, operators are spending vast quantities of monies to drill what we will call "deep wells". For the purpose of this paper, a "deep well" is defined as a well drilled below 15,000' for the purpose of exploring for and producing of oil and/or gas. The first such well was drilled in 1939, but the real increase in this activity started in the 1950's. The statistical trends for the yearly average well depth and number of wells drilled to at least 15,000' are shown in Figure 1.