New Developments in Drill Stem Rotary Shoulder Connections

Many problems in a drilling operation can be caused by excessive contact forces between the drill pipe and the casing or hole wall. The contact force pipe and the casing or hole wall. The contact force is mainly controlled by the hole curvature, drill pipe stiffness, and the axial load on the drill pipe. pipe stiffness, and the axial load on the drill pipe. This paper discusses the relationship between the magnitude of the contact forces and the above three variables, as well as several other less significant variables. Introduction The lateral force with which the drill string interacts with the casing or open hole wall should be of vital concern in a drilling operation. Large lateral forces can result in excessive casing wear, excessive drill pipe and tool joint wear, and key seats in the hole wall. An understanding of the factors that control the lateral contact forces may allow preventative action to be taken before a problem develops. The problem of excessive contact force between the drill pipe and the hole wall has been recognized for many years. It was addressed in 1960 by Lubinski, but it has only been during the last few years that detailed computer modeling of the problem has been feasible. This paper presents the results of a finite element computer study of the variables that affect the magnitude of the contact forces under a variety of conditions. The parameters were chosen to represent conditions that may occur in realistic drilling operations. Finite Element Model During 1975 a consulting firm was contracted and directed by Amoco to write a dynamic triaxial finite element computer program for the analysis of bottom hole assemblies. This program can be used to analyze any multi-component drill string in a wellbore. The drill string can be divided into a maximum of 51 elements of uniform cross sectional geometry and uniform material. An iterative process of solving for deflections and forces is then performed until the drill string deflections converge within the boundary conditions of the borehole. The required input data is a description of the drill string, wellbore diameter, wellbore survey, drilling fluid density, and axial load (weight on bit). The computed data includes the forces and deflections for each node point. Further discussion of the program is included in the appendix. Two drill pipe models were investigated before one was chosen for the study. The first model represented a joint of drill pipe with five equal length finite elements and the tool joint as a single element with its length equal to the tool joint length. This model was unstable under certain combinations of axial load and hole curvatures. The second model represented a joint of drill pipe with two finite elements and the tool joint as a zero length element. The zero length element resulted in a single point of contact with the hole wall rather than a point of contact on each end of a short element. Both models gave the same results for the cases in which the first model would converge, thus the second model was used for the study. Figure 1 shows a diagram of the drill pipe configuration that was used for decreasing curvature and Figure 2 shows the increasing curvature configuration. Table 1 gives the drill pipe and tool joint dimensions that were used in the study. Cases were run for 3-1/2", 4-1/2", 5", 5-1/2", and 6-5/8" drill pipe, with 20", 13-3/8", 9-5/8", and 7" casing sizes. pipe, with 20", 13-3/8", 9-5/8", and 7" casing sizes. The 13-3/8", 9-5/8", and 7" casing sizes will give approximately the same results as 12-1/4", 8-3/4", and 6-1/4" open hole sizes. The effects of hole size, drill pipe size, axial load, hole curvature, length and orientation of the curve, and hole inclination were investigated. Unless otherwise noted, the drill pipe was positioned in the hole so that a tool joint would be at the center of the hole curvature. All the results presented in this paper were generated from a static (non-rotating) model. The results accurately represent the forces which develop while going in or out of the hole with the drill pipe. pipe.

New developments in drilling tubulars are rapidly evolving and represent enabling technologies for the industry's continued advancement of drilling deeper, further and more cost-effective wells. Much focus has been made toward the advancement of drill pipe connection technology to permit high torque drilling of extended reach, directional and horizontal wells. First and second generation high torque connections have been available to the industry for several years. In today's rig market; deepwater, extended reach and ultradeep wells dictate large spread rates that can benefit significantly from reduced tripping times. These same wells often have mechanical and hydraulic load requirements for which today's high torque connections may not be specifically optimized. In response to this need, the development of third generation, ultra-high torque connections is now complete. This paper will present the results of a 2–1/2 year comprehensive effort to design, test, manufacture and field trial a family of connections that were engineered to meet the specific needs of each drill pipe size. Results from extensive laboratory tests and two field trial programs designed to produce harsh, aggressive dynamic loads to the connections are presented. The thread form is a double-start thread that reduces the number of revolutions to assemble the connection by 50%. The thread form also provides a unique dual-radius thread root that offers a step change improvement in fatigue resistance. Conservative estimates suggest that the new connections will save approximately 7–1/2 hours in planned trip time per 20,000 ft well. The new connections provide increased mechanical and hydraulic performance compared to second generation high torque connections while also providing fatigue performance greater than standard API connections. These connections can facilitate more challenging wells, provide increased cost savings and reduce risk during the well construction process. Introduction The current trend to drill offshore in deeper waters, longer extended reach wells and record setting ultra-deep wells is destined to continue. Many rig contractors are presently upgrading or building new jack-up, semi-submersible and dynamically positioned drill ship rigs capable of drilling to 35,000+ ft total depth (TD). One rig contractor, in particular, recently contracted the manufacture of three $650 million USD dynamically positioned drill ships capable of drilling in 12,000 ft of water to well depths of 40,000 ft.(1) Wells that are in the planning stages today demand drill string technology with capabilities that exceed current connection designs and material performance properties. As mentioned above, rig rates have risen dramatically, as have the costs for virtually all services, equipment, tools and materials used by the energy drilling industry. At the same time, existing wells and reservoirs are experiencing accelerated decline rates. Our industry must respond to these realities with advanced technologies that improve efficiency, enabling wells to be drilled more effectively and at acceptable costs. Drill pipe and drill stem materials and connections represent mature technologies. Nevertheless, innovations can and are being developed in this important area critical in the quest to exploit more remote hydrocarbon target zones. The third generation double-shoulder connection presented in this paper represents one advancement that addresses some of the drilling challenges ahead.

Drill string models are of two major types- Conventional and Periodic. Conventional drill string models are widely used due to their simplicity in manufacturing and dynamics analysis. Drill strings are affected mainly by torsional, lateral and axial vibrations. The dispersive or propagative nature of these vibrations can only be analyzed by using periodic drill string models. Drill pipe makes up the majority of the drill string. In reality, at each end of the drill pipe, tubular, larger-diameter portions called the tool joints are located. Since the dimensions of the tool joint are negligible when compared to the drill pipe, conventional drill string models assume drill strings to be uniform structures. The tool joints in drill strings introduce a geometrical periodicity in the structure.A periodic structural component is comprised of a repeating array of cells, which are themselves an assembly of elements. The elements may have differing material properties as well as geometric variations. The periodic structures act as mechanical filters for the wave propagation. A material or geometrical change in the structure causes a disruption to the continuous propagation of vibration waves.There are three types of waves propagating in rotating structures: torsional, flexural (bending) and longitudinal. Of these waves, torsional and longitudinal waves are dispersive while flexural waves are non- dispersive. The proportions of the waves which are dispersed vary according to the Wavenumber. The wavenumber is a property of the wave and depends on the structural, material and geometrical properties of the wave guide. Waveguide is the medium through which a wave travels. The wave number, and hence the dispersion and propagation characteristics of waves can be tuned by varying the material and geometrical periodicity in the drill strings.This paper presents the vibration propagation and attenuation characteristics in conventional and periodic drill string models. The periodic drill string model is developed such that it can be easily scaled to a real drilling rig model. The research also features a laboratory setting which comprises a mini drilling rig and actual drilling samples. These features ensure robustness of the dynamics analyzed for the periodic drill string model.The research findings are analyzed under zero and non- zero borehole drill string interactions. Vibration information is collected from upper and lower parts of the drill string models to compare the propagation and attenuation characteristics. Proximity sensors are used for the data acquisition which is then analyzed using frequency and power spectrum graphs. The time and frequency domain vibration propagation characteristics are investigated for both the conventional and periodic drill string models. Laboratory testing analyzes (1) introduction of stop and pass band regions in frequency spectra by periodic drill string models, and (2) vibration attenuation in torsional and lateral vibration modes. The tests confirm the introduction of stop bands in frequency spectra for the periodic drill strings, while they were absent and had an all pass-band for conventional drill string models.The research opens up a new method of passive control of drilling vibrations- by introducing tool joint designs which could be tuned to efficiently dampen out the harmful vibrations affecting the drilling rigs.

Both Saudi Aramco and Total Indonesia found benefits in selecting 4 in. drill pipe with streamlined double shoulder connections for the drilling of wells, for which the 3 1/2 in. drill pipe was unsuitable. Although dealing with different environments and applications, these benefits can be summarized in "successfully drilling longer slim holes with a drill string having enhanced torsional, tensile and hydraulic characteristics at a lower overall cost". For the Saudi Aramco QTF field, Extended Reach Drilling (ERD) was required with the objective to deliver pay zones located at measured depths of 18,000 ft (for the 1,500 HP rigs) and 25,000 ft (for the 2,000 HP rigs). These depths correspond to step outs ranging from 13,000 ft to 20,000 ft respectively from the drill site. For its Kalimantan field, Total was in a need of higher torsional capacity and also an improvement of the hydraulic characteristics of the drill string. Selecting a larger size of pipe was the retained option against an upgrade of the rig pump installation. The casing and drilling program remained unchanged with the drilling of a 6 in. hole after setting the 7 in. casing, adding a constraint for fishability of the string. In both cases, fishability and torque objectives made the selection of the appropriate connection essential. The selected double shouldered connection maintained a tool joint outside diameter similar to standard 3 1/2 in. drill pipe tool joints, that maintains fishing ability of the 4 in. pipe, in casing and open hole, despite the pipe size increase. The streamline connection design provides 22,000 ft-lb working torque, an outside diameter of 4–7/8 in. and an oversized internal bore that promotes hydraulic efficiency. Other important improvements include considerable gain in pipe resistance under buckling loads, increased available pressure at the bit, better telemetry for the MWD and LWD tools and improved hole cleaning and rate of penetration. Introduction Drilling deeper, slim hole wells has revealed limitations of 3 1/2 in. drill pipe traditionally used to drill the 6 to 6–1/4 in. hole sections. The level of torque that API rotary shoulder, as well as first generation double shoulder connections, can deliver does not match the new requirements for these deeper drilling programs. This increase in drill string length also puts an additional constraint on hydraulic performance. This encouraged drilling engineers to re-evaluate the drill string design requirements and select a new configuration of pipe that would respond to these new requirements. This paper addresses these pipe and connection design considerations and provides two case histories showing the benefits that were realized from using this new drill pipe design configuration. Over 1,400,000 ft of this pipe has been built to date and is in service all over the world. It is also important to mention that this new drill pipe arrangement can also be used for drilling upper hole sections eliminating the need for a string 5 in. drill pipe in many applications. Streamlined Double Shoulder Connections for 4 in. Drill Pipe There has been increasing requirements for drill pipe with improved hydraulic performance and mechanical properties to replace 3–1/2 in. drill pipe traditionally used in slim-hole drilling.

This paper describes the development, design, lab and field testing of a new generation rotary shouldered connection for BHA components.Originally pursued to enable data transmission through the BHA, this new connection further provides a dramatic increase in fatigue resistance to cyclic loads.Additional benefits from the optimized design are gained in handling and repair performance.Lab results from resonant bending fatigue tests are discussed.Successful results from the industry's first field trials of these new connections are also provided.The paper describes a critical field application where the new BHA connection has been selected to provide advanced fatigue resistance.The paper further illustrates how the connection may be used in the harshest fatigue environments to minimize risk of failure and improve well economics. Introduction New developments in drilling tubulars are rapidly evolving and represent enabling technologies for the industry's continued advancement of drilling deeper, longer reach and more cost-effective wells.Much focus has been made toward the advancement of drill pipe connection technology to permit high torque drilling of extended reach, directional and horizontal wells.During development of these high torque connections, manufacturers have also advanced the connection fatigue performance through the use of proprietary thread forms. Yet there has been no significant development in bottom hole assembly (BHA) connection technology since the introduction of stress relief features (SRF) and cold rolling practices to the thread roots.The predominant use of American Petroleum Institute (API) NC and Regular connections within the BHA serves to maximize the compatibility of the industry's inventory of BHA tools, but does not necessarily optimally address the cyclic loading conditions that exist within every BHA.Fatigue continues to be the most common failure mode in the BHA and represents one of the most costly drilling problems, often requiring lengthy trips, open hole fishing and sidetrack operations. In order to address this industry need, a comprehensive two-year program to design, develop and test a highly fatigue resistant BHA connection was pursued.As a result of the program, a new proprietary connection was developed with test results that indicate at least nine times improved fatigue performance when compared to standard API connections. Developed for the IntelliServ® network, the new connection incorporates a secondary internal shoulder, which can house inductive coils to permit telemetry transmission across the drill collar connection. Project Background The IntelliServ network, a high-speed, bi-directional, real-time drill string telemetry system, has been under development since 1997.This network utilizes conventional drilling tubulars modified to incorporate a 3/16 in. diameter high-speed data cable running the length of each joint.The cable terminates at unique, inductive coils that are installed in the pin nose and corresponding box shoulder of every connection. A double-shouldered connection provides an ideal location for coil placement, with each coil installed in a protective groove in the secondary torque shoulder.Figure 1 illustrates a coil installed in the pin end of a double-shouldered drill pipe connection.

A need exists for drill pipe that offers improved reliability and extended life in re-entry drilling programs where the radius of curvature is less than 60ft (i.e., >95-deg/100 ft). Steel, aluminum, and composite drill pipetraditionally utilized in these short radius drilling operations often exhibit abbreviated lives stemming from fatigue, wear, and/or physical damage. With an elastic modulus of approximately 17 msi, titanium pipe offers enhanced flexibility and reduced fiber stresses compared to steel pipe when rotated in holes of high curvature. Utilization of the most widely used titanium alloy, Ti-6Al-4V, offers a high nominal yield strength of 120 ksi with a density 56% that of steel. Combined with good corrosion and fatigue resistance in drilling and down hole fluid environments, this titanium alloy isa lightweight, highly flexible, robust, and fatigue-resistant drill pipe material. A practical and cost-optimized Ti drill pipe joint design consists of a seamless Ti-6Al-4V alloy pipe body, which is produced in standard API sizes and Range 2 and 3 lengths, to which steel tool joints are mechanically attached to the upset ends. The steel tool joints offer the advantages of lower tool joint costs, standard drill pipe make/break connection behaviour, the option for tooljoint hard banding, and elimination of welded joints. Successful development of titanium drill pipe assemblies for short-radius drilling included appropriate conditioning of the OD and ID pipe body surfaces to maximize fatigue life, optimizing the pipe end upsetting procedure, establishing the tool joint-to-pipe attachment methodology, and design and testing of a high-integrity tool joint-to-pipe connection and tool joint for optimum fatigue performance. This paper overviews these developments and the laboratory test results used to establish critical performance behaviour and requirements for 2–7/8 in. OD titanium drill pipe for short-radius drilling. An update on recent field experience with titanium drill pipe utilization invarious short radius drilling programs is provided as well. Introduction This program was undertaken in late 1996 with the objective to develop titanium drill pipe for short radius drilling applications. The pipe size selected for this development was 2–7/8 in. × 2.151 in. ID with 3–5/8 in. OD × 1–3/4 in. ID NC26 tool joints. The pipe body is dimensionally the same as API2–7/8 10.40 lb/ft steel pipe which is widely used. The NC26 tool joint is a good match for the pipe and is also commonly used. Titanium has five attributes that make it an attractive choice compared to steel for short radius drill pipe:*Titanium has a density of 0.160 lb/in3 compared to 0.283 lb/in3 for steel orit's about 43% lighter.*Titanium has an elastic modulus of 17 million psi compared to 30 million psifor steel or it is 57% as stiff as steel.*Titanium is more corrosion and erosion resistant than steel.*Titanium does not suffer corrosion fatigue. The fatigue performance in air issustained in the drilling environment.*Titanium pipe has a yield strength of 120,000 psi, which equates to a strength to weight ratio of 1.54 times that of S-135 steel pipe. Even though all these attributes contribute directly to the pipe's attractiveness for short radius drilling, the low modulus is the primary characteristic that gives titanium the advantage over steel. It is desirable inthe industry to drill through a radius of curvature of 50 feet or less and have a service life greater than 500,000 cycles.

With the increasing intensity of oil and gas field exploration and development, oil and gas wells are also drilling into deeper and more complex formations. Conventional steel drilling tools can no longer meet the requirements of ultra-deep, high-temperature and high-pressure wells. The paper first analyzes the advantages of titanium alloy drill pipe based on basic performance of titanium alloy drill pipe. The experimental results show that the basic properties of titanium alloy drill pipes meet the operating standards of the petroleum industry. Then the buckling performance of titanium alloy drill pipe and steel drill pipe is compared, the calculation results show that the buckling performance of titanium alloy drill tools is slightly lower than that of steel drill tools. Secondly, the maximum allowable buildup rate of titanium alloy drill pipe and steel drill tool is studied. The research shows that under the same condition of the drill pipe outer diameter, titanium alloy drill pipe can be used for a smaller curvature radius and greater buildup rate. This advantage of titanium alloy drill pipe makes it more suitable for short radius and ultra-short radius wells. Finally, taking a shale gas horizontal well as an example, with the goal of reducing drill string friction and ensuring drill string stability, a comparative study on the application of titanium alloy drill pipe and steel drill pipe is carried out. The results show that titanium alloy drill pipe has a wider application in the field, and is suitable for operations under various complex working conditions.

The drill-stem test [DST] is a temporary completion designed to sample the reservoir fluid and to establish the possibility of commercial production. It also yields values for the permeability capacity of the formation, for wellbore damage and for static reservoir pressure. The conventional interpretation is based on the assumption that the production rate is constant during the flow period. In fact, flow is not constant because the fluid column rising in the drill pipe exerts a time-variable back pressure on the face of the formation exposed in the wellbore. The effect of the resulting variable flow rate on damage ratio obtained from conventional DST analysis is studied in this paper. For the case of high fluid productivity, conventional analysis yields a higher formation capacity and a lower damage ratio than the true values. The error in the damage ratio is particularly large. The method of Odeh and Selig1 will improve the flow capacity calculation considerably. However, they do not calculate the formation damage. A method for calculating the damage ratio is suggested here. INTRODUCTION The drill-stem test [DST] is a production test carried out through a temporary completion; it is designed to sample the reservoir fluid and to determine the possibility of commercial production. The test is carried out by attaching a fluid sampler to the drill collar and lowering the sampler to the zone to be tested. One or more packers, which are part of the tool, are set to isolate the formation from the mud column in the wellbore; then the formation fluid is directed into the sampler and subsequently into the drill pipe. A clock-driven recording gauge records the pressure variations. After a short period of production, the valve between the drill string and the sampler is closed; the recording of the bottom-hole pressure continues and corresponds to a short buildup test. The plot of this pressure on a linear scale vs [T+ ?]/? on a logarithmic scale is a curve, an analysis of which yields values for formation capacity [kh], wellbore damage, and static reservoir pressure.2

The flow testing and evaluation/stimulation of horizontal wells in oil and gas reservoirs is an important process used by operators in both openhole and cased hole applications. The information gained from openhole flow tests; permeability, flow rates, skin damage and water production is used to calculate well deliverability and helps confirm the appropriate remedial activity. Although well testing is common in all reservoirs, the testing of sweet or sour horizontal wells is still a significant challenge for operators and service companies alike. The overall length of the horizontal section 300–4500 ft (100–1500 m) results in production of multiple intervals making flow and pressure transient analysis difficult. In addition, the testing of sour wells has been very limited due to the concerns of H2S embrittlement of conventional drill pipe or tubing. In horizontal wells the challenge is to safely, quickly and selectively test the horizontal section of the well and use this information to implement remedial stimulation or workover to improve hydrocarbon production. This paper will review a new technology which uses an inflatable straddle packer "Drill Stem Test" (DST) tool deployed into the horizontal well using a "Coil in Coil" coiled tubing string configuration. An electrical conductor is located inside the inner string which allows for "real time" formation evaluation and tool operation. The inner coil string is used for all well flow and stimulation operations with the coil in coil annulus utilized for circulation operations and packer element inflation. More importantly, the outside string also provides for pressure monitoring, flow containment and well control in the unlikely event of a failure of the inner string. Using the test tool, the operator can set the straddle packer on a variable length 12–150 ft (4-50 m) of openhole zone and conduct a flow test followed by a pressure build-up for pressure transient analysis. If the evaluation of the real-time data indicates a wellbore skin, the same tool can be used to selectively stimulate the formation; while monitoring bottom hole pressure, without unsetting the packer and then repeating the flow or pressure buildup test. Since the evaluation/stimulation process from reservoir to separator is "closed loop", the production optimization of long horizontal sections can be implemented in a more cost effective and safer manner. Introduction Horizontal drilling has emerged as an important technology in the Canadian and international oil and gas industry. As operators pursue the continued development of more challenging reservoirs, using both new and existing wells. Horizontal wells are typically used to: intersect more reservoir to increase well deliverability, reduce the pressure differential to the wellbore allowing additional production from pressure depleted reservoirs, or avoid the production of bottom drive water zones. As horizontal drilling applications have increased so has the debate on the differences between conventional overbalanced and underbalanced drilling (UBD) technologies. The drilling of the horizontal well results in the openhole zone being exposed to drilling fluids and cuttings for extended periods of time versus vertical well development. In the vertical wellbore the extent of damage is limited and can usually be removed using cased hole selective stimulation and evaluation techniques. P. 493

Industry advances continue to enable pursuit of more challenging drilling targets with complex well bore trajectories. Many of these targets are in costly deepwater and/or remote operating areas. Demand for a practical, field-proven drill pipe fatigue management system has grown as drill string failures due to fatigue contribute to a significant amount of non-productive time and cost. The response to this demand has been the development of an engineered approach that combines pipe section positioning and inspection scheduling based on estimated fatigue damage rather than rotating hours or footage drilled. Successful real-time field implementation with ongoing drilling programs demonstrates that the cumulative fatigue damage technique is a valuable and proven tool for risk mitigation and cost reduction. The cumulative fatigue damage technique and its implementation have been introduced in previous literature [1,3,8,10]. This method of monitoring fatigue damage due to rotary operations allows the pipe to be evaluated under real-time operating conditions along a specific section or the entire length of the drill pipe. Monitoring begins at spud and is performed on each joint of drill pipe as it traverses along the well path to total depth (TD). This not only allows a quantitative measure of the relative fatigue damage accumulated joint by joint for the drill pipe, but also provides the opportunity to manage logistics, forecast pipe inspections and position pipe sections to minimize cumulative drill string fatigue damage. The cumulative fatigue damage technique has been successfully applied in the field[1,10]. Hind casting, pre-drill planning and real-time analyses have been utilized for assessing drill string design as well as pipe management. The current case study further demonstrates the methodology introduced in the previous literature and illustrates the modeling and management of fatigue damage over a three well project. The subject operator originally anticipated that pipe inspection may be required before each well to mitigate costly historical drill pipe failures. However, the cost and logistical challenges of mid-program pipe inspection in remote operations could not be ignored. Described is the pipe management strategy employed to complete the drilling program without drill pipe failures and without the need for any mid-program inspections. In addition, the inspection results post TD of the third programmed well have been evaluated and correlated back to expected pipe damage, making this an excellent case study for the further deployment of this technology.

In field data from slug test (decreasing flow rate) DSTS, an initial period of constant flow rate can often be observed. This may be a consequence of critical flow. "Critical flow" means that flow rate is independent of the pressure drop across the flow restriction. In the case of compressible fluid flow, this implies that the flow velocity is equal to the sonic velocity in the fluid. This was suggested by Ramey et al. in 1975. However, critical (constant-rate) flow was not included in their analysis of slug test DST flow period data. A new method which does consider an initial constant flow rate for a slug test was found. Graphs for the type-curve matching method are presented and field data are shown. Introduction Often in drill stem testing, the flow periods are characterized by a pressure trace which increases with increasing time, showing the accumulation of liquid in the drill string. In the expected case, the pressure-time trace is linear, showing constant-rate pressure-time trace is linear, showing constant-rate production. In other cases, the pressure-time trace production. In other cases, the pressure-time trace curves and is concave to the time axis. This shows a decreasing flow rate. In the case that formation pressure is too low to lift a column of reservoir pressure is too low to lift a column of reservoir liquid to the surface, the well may stop flowing before the tester valve is closed. This results because the head of liquid in the drill string becomes equal to initial formation pressure. This sort of test is similar to a pressure transient test called a "slug test" by Ferris and Knowles in 1954. The word "slug" refers to the maximum volume of liquid which may be produced by the time the well becomes static. produced by the time the well becomes static. A similar test involving the cooling of a batch of hot water was reported by Beck, Jaeger, and Newstead in 1956. Cooper et al., in 1967, reported the results of a field test in a static water well from which a float was suddenly removed, giving the appearance of the sudden removal of a quantity of water equal to that displaced by the float. Maier presented an approximate analysis of the equivalent DST presented an approximate analysis of the equivalent DST problem in 1970. problem in 1970.Van Poollen et al., in 1970, and Kohlhass, in 1972, applied the Cooper et al. solution to DST flow period data analysis. Although most current studies period data analysis. Although most current studies reference a study by Jaeger in 1956 which included a sandface resistance similar to the skin effect, most recent works do not include wellbore damage effects. A solution including the skin effect was presented by Ramey and Agarwal in 1972, although use of the solutions was not demonstrated. Papadopulos et al. presented extended results for the zero skin effect presented extended results for the zero skin effect case in 1973. The most complete discussion of DST applications of the slug test was presented in 1975. Three new slug test type-curves were developed for analysis of flow period data, and three field cases were analyzed. This study was included in the Earlougher monograph in 1977, and large-scale type-curves were printed with that monograph. printed with that monograph. Finally, Fenske showed that pressure buildup data for a well produced a short time (with wellbore storage) would follow the slug test type-curves. This is a potent observation. It means that the slug test type-curves may work for the initial shut-in, as well as for flow period data. This establishes the importance of slug test type-curves for DST work whether the test would normally be classified a "slug test" or not. Although not within the scope of this study, slug test type-curves may be used to match the initial shut-in for a DST following a very short initial flow to provide permeability, skin effect, and extrapolated initial pressure. One of the most important observations made from attempts to match field data with slug test type-curves is that there is often an initial constant-rate flow period before the rate begins to decline. Reference period before the rate begins to decline. Reference 1 pointed out this phenomena was related to conventional DST results for liquid flow wherein flow rate was constant for both flow periods: "Before proceeding with the presentation of the 'slug test', it should be pointed out that the conventional DST… contains the seed of a paradox.

In underbalanced drilling the use of air as an injected gas sets up the potential for oxygen corrosion. Membrane nitrogen with about 5% oxygen eliminates the chance for fire or explosion, but does not solve the corrosion problem. Natural gas or cryogenic nitrogen eliminates the chance for oxygen corrosion, but does not always eliminate the chance of corrosion from other down hole acid gasses (Hydrogen Sulfide, H2S, Carbon Dioxide, and CO2). Any corrosion that occurs while drilling will be forced by some drilling fluid or drilling operational procedure such as KCl fluids, aerated mud, or floating mud cap operations. The objective of this study is to identify some of the practical elements of corrosion encountered with underbalanced drilling and their optimum solution by development of an advisory system based on field cases and expert opinions. This advisory system is intended to be a field guide for the drilling engineer or rig supervisor. Corrosion is a matter of concern to the drilling contractor because of pitting or loss of steel in the drill pipe. The advisory system is developed by proposing a set of guidelines for the optimal practices to minimize corrosion in underbalanced drilling operations. The optimum practices collected from data and experts' opinions, are integrated into a Bayesian Network BN to simulate likely scenarios of its use that will honor efficient practices when dictated by varying certain parameters. These parameters are measuring corrosion, identifying corrosion types, drill pipe and corrosion, treatment methods for H2S corrosion, CO2 sources and treatment, different methods to test for corrosion, general corrosion prevention and treatment, treatment methods for formation water and makeup water, and recommended practices to minimize corrosion in underbalanced drilling operations. To the best of the authors' knowledge, this paper is the first study to develop an advisory system for minimizing corrosion problems. The developed software solutions on corrosion will be demonstrated such as using mechanical means to reduce O2 concentration and inhibitors for pipe coating. Finally, the advisory system list recommendations for all types of underbalanced drilling (flow, aerated, foam and mist) to minimize corrosion problems.

Settling behavior of spherical particles in eccentric annulus filled with viscous inelastic fluid

Fatigue life of drill pipe is studied systematically based on reliability analysis. Calculation results show that bending and tensile stress in drill pipe body is significantly greater than that in the tool joint during drilling process. Drill pipe body’s fatigue strength is about 500MPa under the condition that the stress ratio is -1. The fatigue strength of tool joint is about 360MPa under the condition that the average tensile stress is 496MPa. The fatigue fracture position of drill pipe is concentrated on pipe body, and most fatigue cracks originate from pipe’s outer surface. Compared with material fatigue life, the fatigue life of whole drill pipe is significantly lower. Under the condition that the confidence level is 95% and deviation is 5%, drill pipe’s fatigue life distribution is normal distribution while the stress amplitude is 660MPa, 620MPa, 580MPa and 540MPa respectively. With the decreasing of stress amplitude, the peak of logarithmic fatigue life’ probability density distribution curve decreases gradually, and its dispersion increases gradually. Drill pipe’s fatigue life prediction equations whose reliability are 50%, 90%, 99% and 99.9% are calculated separately.

Drill-stem testing has advanced from simple sampling of the formation to complete pressure buildup analysis. This paper reviews the mechanical arrangement of the tool, its running and pressure measurements. Various typical drill-stern test pressure charts are shown as an aid in trouble-shooting. Purpose THE ORIGINAL PURPOSE of drill-stem tests included recovery of a sample of the formation fluids and possibly measurement of the formation pressure. Today, the nature and use of the drill-stem test is more sophisticated and most techniques developed for drawdown and buildup tests have been adapted to the shorter drill-stem test. These might include computation of formation permeability, k, skin, s, flow efficiency or damage ratio, D.R., productivity index, P.I., and radius of investigation, ri. At times, reservoir discontinuities such as faults, small reservoirs, two-layer performance, lenses in the pay and fluid contacts may be recognized. A sample of the formation fluids is usually caught at near formation pressure during the test and brought to the surface without release of pressure. If properly removed and transported, such sample might be analysed in a PVT laboratory. At present, the sample usually is only used to establish fluid-type, gas-oil ratio, viscosity, gravity, etc., as measured in the field. In a drill-stem test the pipe above a shut-off valve is filled with air adjusted by water cushion as the pipe is lowered into the mud-filled well. This valve can be intentionally opened and closed after the pipe has been lowered to the desired depth and packer, set to seal off the mud liquid within the annulus of the well. Thus the well may be produced against a controlled amount of back pressure when the tool is initially opened. Test Procedure-Mechanical Equipment Most drill-stem tests taken today are using equipment and procedures developed by major service companies. Some of the tools involved and typical charts for two such companies are included in this paper as exhibits A and H, respectively, to give the reader an appreciation of complexity. Two or more bottom hole pressure gauges are usually employed. The upper gauge measures the pressure inside the drill pipe or tubing string below the shut-in valve. The lower gauge measures the pressure on the outside of the tool. Both gauges are located near the bottom of the equipment. A section of slotted pipe is used to permit entry of the fluids from the well bore below the set packers into the inside of the string of pipe. To reduce buildup of pressure ahead of the unset packer while it is being lowered into the well, fluids are permitted to flow through these slots and various other mechanisms located below the shut-in tool. Such fluids constantly move from below the unset packer through the pipe to the annulus above the packer while the tools are run into the well. In most cases this technique results in a shorter running time without damage to the tools or plugging of the slots or other restrictions in the flow string below the shut-in tool in the drill pipe.