Drillstring Analysis With a Discrete Torque/Drag Model

Introduction Drill pipe, and the connections used to join the pipe together, have had a long history of development and improvement. With the growing use of high tensile-strength pipe, the rotary shouldered connections used to join the lengths of drill pipe have become more critical. Fatigue-type failures of rotary-shouldered connections, or tool joints, have become a cause of much concern to operators and manufacturers. Most fatigue tests on tool joints have been made on the basis of bending moment applied vs number of cycles, rather than on the basis of stress vs cycles. A desire to learn more about the nature of stress in a tool joint due to bending caused a rather intensive experimental study to determine what actually happens to cause fatigue failure. It was known that a tool joint with insufficient make-up torque was subject to early fatigue failure. Therefore, the establishment of the relationship between make-up torque and allowable bending moment would enable a testing engineer to better correlate the results of various tests. The problem of calculating the stress in a tool joint due to an applied bending moment was complicated by: the effect of unknown stress concentrations; the applicability of the well known formula S = Mc/I; and the question of whether to use the combined cross section of the pin and box in calculating the moment of inertia I.

The Provost Dina 'X' Pool is a turbidite sand with a pay zone of up to 20 m at a depth of 200 mSS. The field contains approximately 1.2 million m3 of oil and there is a bottom water aquifer with partial pressure support in parts of the field. Most of the vertical wells in the field shut-in due to high water cuts after a relatively short period of production. Therefore, a numerical simulation study of the whole field was undertaken in order to improve recovery by infill drilling as well as by investigating different operating strategies. This paper describes the integrated team approach taken with input from the geological, production and reservoir engineering specialists to construct a reservoir model. The model has been successfully history matched and used, in turn, for predicting the performance of the field under existing conditions as well as a variety of infill drilling and operating scenarios. Results indicate that significant water coning, which would be observed with new vertical wells in certain areas of the pool, can be reduced through horizontal infill wells. Despite the potential technical success of horizontal infill wells, they were not economically feasible in this particular reservoir and vertical infill wells were the preferred choice. It is shown that a combination of carefully planned vertical infill wells and a pressure maintenance program is able to boost the ultimate recovery by 34% while keeping the development costs to a minimum. Results of various operating strategies are presented and the optimum field development scenario implemented in the field is outlined. The initial actual reservoir behaviour is discussed in the light of the results from the simulation study. Introduction The Provost Dina 'X' pool was discovered in 1988 at an initial pressure of 6450 kPa. The reservoir is located in east central Alberta, south of the town of Consort. The formation is a turbidite sand with a limited bottom water aquifer support. The production from the pool began with the discovery well 05-15-35-06 W4M and, to date, a total of 11 wells have delineated a reservoir area of slightly more than 32 ha. (see Figure 1). Historically, most of the vertical wells in the field experience high water cuts after a relatively short period of production. Thus, a significant portion of the reserves cannot be produced because of water coning. Infill drilling can compete favourably with BOR processes for the recovery of the bypassed oil for much less investment and operating cost. As the existing vertical wells have to be operated above the critical water coning rates to be economic, horizontal wells become another option for infill drilling. The field experience indicates that horizontal wells can reduce the water coning tendency while increasing the oil production. However, further improvement to oil production rate of horizontal wells is still limited by the encroachment of the water cone when the bottom water exists. Therefore a simulation study was undertaken to investigate the feasibility of increasing reserves by infill drilling with horizontal and vertical wells. Model Construction The black oil simulation module (SimBest II) of The Petroleum WorkBench reservoir management package of Scientific Software-Intercomp was used to conduct this simulation study. SimBest II is a three-dimensional, fully implicit reservoir simulator which is capable of handling as many as three fluid phases and five components in a dual and/or single porosity mode. P. 555

A comprehensive analysis on the longitudinal fracture in the tool joints of drill pipes

A laboratory and field study directed at improved well performance of horizontal wells is discussed. During the study, several wells were matrix acidized using bullhead and coiled tubing placement techniques. The study performed in carbonate reservoirs indicates acid placed with coiled tubing diverted with foam provides excellent zone coverage and damage removal. Conventional bullhead techniques do not result in effective damage removal. The study emphasizes the evaluation of the treatment results and the development of improved acidizing techniques. Laboratory simulations of matrix acidizing indicate proper placement techniques are essential. This observation is supported by field data in oil wells completed in carbonate reservoirs. The key to successful damage removal is 1) the placement of acid via coiled tubing and 2) proper diversion. Production logging and well performance data support this claim. The proposed treatment is applicable in both horizontal and vertical wells completed in carbonate reservoirs.

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.

Length and profile shape of horizontal section of the production well is one of the main issues in the justification of horizontal well completion. Justified choice of horizontal well completion and profile design is based on the main objectives: provide high initial rate, maximize the cumulated gas and condensate production, reduce the risk of well drilling and completion, extend a period with water free production, hence resulted in the maximum NPV. The main factors that influence the choice of horizontal well profile are the geological structure of the productive formation, its reservoir properties, the location of formation fluid contacts, formation anisotropy, the ratio of vertical and horizontal heterogeneity. In this paper we investigate the influence of mentioned geological factors on the choice of horizontal well profile. Various profiles of horizontal wells- directional, horizontal and U-shaped have been considered for gas condensate reservoirs. The analysis was conducted on the basis of hydrodynamic modeling Eclipse 300 using a function of multi-segment well. After choice of the optimal length for the horizontal section of the well, a simulation was performed. Also there was a comparison of the performance for directional and U-shaped horizontal wells with the same length. During comparing the well performance well productivity, cumulative gas and condensate production, inflow profiles, the conditions of liquid removing from well bottom of were evaluated. Sensitivity evaluation of the optimal profile selecting to the reservoir permeability and its anisotropy was performed. It helps to take into account the effect of uncertainty on the performance of the well. Selecting a profile of the horizontal section of the well is one of the main issues in the design and affects not only the final gas and condensate recovery, but also helps to clarify the geological structure formation during logging, and enable the development of all productive layers, reduce the risk of complications during the operation. Structural features of horizontal wells unlike allow to obtain vertical flow rates several times superior performance of vertical wells. And the increase in horizontal wells is provided not by increasing the drawdown, and by increasing the filter surface. Productivity is limited in the vertical wells of the reservoir reveals the thickness, whereas the thickness of a predetermined value for the formation and drawdown -the geometrical parameters of the liner and, consequently, horizontal wells depends on the length of the horizontal wellbore. The horizontal wellbore completion may be regarded as an effective method for production of hydrocarbons, and as a method of stimulation. Engineering and technology horizontal drilling, completion fluid, their performance, conduct work under stimulation to them, economic indicators drilling and operation of horizontal wells devoted several thousand research. At the same time question the justification of the optimal design and the length of the gas and gas condensate wells are virtually unexplored. Studies on this topic have been done by Z.S. Aliyev, V. Sheremet and V.A. Chernykh. Z.S. Aliyev in one of his works says that the only way to study the optimal design of horizontal gas wells drilled in inhomogeneously layered strata, is a numerical solution to this problem through the creation of geological and mathematical models of fragments of such deposits and the joint solution of unsteady, multidimensional, multiphase and multicomponent filtering the horizontal trunk with the equation of motion with a variable flow rate of the mixture along the length of the barrel. In this paper we provide a rationale for completing horizontal wells for specific geological conditions of the N-th gas condensate field located in the east of the autonomous area.

SummaryThe first buckling solution was developed by Lubinski and Woods. When the differential equation describing buckling was derived, this solution was found to be an exact solution for vertical wells. Since these results were published, no other exact analytic solution has been discovered. Many numerical results have been obtained, however, suggesting that other solutions did exist. Because the buckling differential equation is nonlinear, it is not surprising that no other analytic solutions have been discovered. This paper presents three new analytic solutions for the vertical well problem and two new analytic solutions for the horizontal well problem. These analytic solutions are valuable both for predicting previously unanticipated buckling behavior and for providing guidance in further numerical evaluations of this problem.In this paper, these five solutions are described, including techniques for evaluating the analytic functions. Buckling length change calculations are determined analytically, and pipe curvature, bending moment, and bending stresses are evaluated. The contact loads between tubing and wellbore are determined, then used to limit the range of validity of the solutions. The critical force for helical buckling is determined for horizontal wells.Possible applications for these solutions include the analysis of bottomhole assemblies, drillpipe, casing, and tubing. The solutions are simple formulas, but require computer evaluation of the analytic functions.

Deuxieme partie de l'etude de conception d'un outil diamant equipe d'un compact a diamant polycristallin (PDC): presentation des algorithmes utilises par le logiciel PDCWEAR (FORTRAN 77). PDCWEAR analyse les performances et l'usure de ce type d'outil diamant en cours de forage. Un cas concret est analyse a l'aide de PDCWEAR, des conclusions en sont tirees quant aux effets de profil de l'outil, du nombre de dents, de la vitesse de rotation, de l'assistance d'un jet d'eau et du mode d'usure des dents

Properties of gas condensate reservoirs are particularly difficult to study due to the composition and phase changes of light components that occur during the reservoir depletion. At the first stage of their discovery, these reservoirs behave like gas reservoirs during depletion. Once the dew point pressure is reached at reservoir conditions of pressure and temperature a retrograde condensation phase develops in the reservoir. Liquid condensation in the formation can result in severe loss of well deliverability and therefore of gas and condensate recovery, which will certainly lead to a loss of income. In this study, the performance of horizontal wells and vertical wells in Gas condensate reservoirs is investigated under various depletion schemes. The expected low horizontal well drawdown pressure, compared to vertical well for the same flow rate, considerably reduces retrograde condensation. A reservoir simulator is used to compare liquid saturation profiles in the case of horizontal and vertical wells in Gas condensate reservoirs. The influence of the horizontal well length section and reservoir thickness on horizontal well productivity, and condensate recovery were also simulated. Another factor investigated in this study is the effect of drilling a horizontal well in a Gas condensate reservoir that has already been developed by vertical wells. To illustrate the productivity increase due to the use of horizontal wells in gas condensate reservoirs, Djebel Bissa field data are presented and discussed using a compositional single well model (VIP simulator). The main results of this investigation are: Because pressure drawdown is smaller for a horizontal well than that for a vertical well, the problems related to the liquid deposit can be reduced by the use of horizontal wells. Layers of value of kh contains the most liquid accumulations.

Interference tests provide valuable information about reservoir characteristics such as areal average transmissivity, storativity, and degree of communication between wells. Due to the larger radius of influence and larger contact area of a horizontal well with the formation than its vertical counterpart, the transmissivity and storativity obtained from interference testing of horizontal wells would be much more representative of the formation than the ones obtained from interference testing of vertical wells. This paper provides the dimensionless pressure drop and dimensionless pressure derivative type curves for interference testing of horizontal wells and the appropriate equations to be used in conjunction with the type curves in order to determine transmissivity and storativity from field data. Solutions were also obtained for interference testing between horizontal and vertical wells. The deviation of this solution from the exponential integral solution is explained. Dimensionless time and dimensionless distance criteria is established for a particular set of dimensionless parameters to explain this deviation. Guidelines are given for interference test design.

A well casing for a horizontal well or an extended reach well is subjected to local wear of wall thickness on its inside surface due to contact with tool joint or wireline.It is reported that the collapse strength and the burst strength of worn casing are well analyzed as an unstable problem by the finite-element method (FEM) and that the decrease ratios of these strengths due to wear are formulated using FEM simulation results. However, the applicability of formula with two wears is not clarified by comparison with experimental result.In this paper, the collapse strength with two wears is analyzed by FEM and by the derived formula and is compared with an experimental result of a literature. Furtheremore, the relationship of collapse strength between casing with two wears and casing with uniform weae is analyzed.Following findings are conducted.1. The experimental collapse strength of uniformly worn casing was affected by specimen length/outside diameter (L/D). Therefore, the correction due to L/D in the elastic collapse range is necessary.2. The relation of collapse strength between with two wears and with uniform wear, is determined by yield strength, outside diameter/wall thickness ratio and weae ratio. Namely, the result of literature is one of these relations and is not a general relation.3. The proposed formula is applicable considering additional FEM results.

For a horizontal well or an extended reach well, which is promising for well construction in . future, a well casing is subjected to local wear of wall thickness on its inside surface due to rotational contact with tool joint or drill pipe during drilling. Collapse strength of worn casing is analyzed as an unstable problem by the elastic-plastic finite-element method (FEM) and the decrease ratio of collapse strength due to casing wear is formulated by nonlinear programming using parameters of the wear shape. The elastic-plastic FEM is fully applicable as values calculated by the FEM program agree well with those of experiments. It was found that the decrease ratio of collapse strength of a worn casing is linearly proportional to the decrease ratio of wall thickness in both modes of plastic collapse and elastic collapse, and that the apical angle of the wear shape has a slight influence on collapse strength.

Introduction Divinyl benzene co-polymer beads, better known as plastic beads, have been used for reducing torque and drag in conventional drilling operations for 17 years. Over the last four years, they have also been utilized to reduce friction in horizontal wells when drill pipe is not sliding at a fast enough rate, or is not moving at all. Co-polymer beads have also gained recognition as a means of reducing friction in coiled tubing workovers. Friction is reduced by introducing co-polymer beads between the drill string and bore hole. Laboratory testing and field experience have developed methods for reducing friction through specific application techniques. Application of the beads can vary, from spotting small "pills" in specific sections of the bore hole to carrying a concentration of beads throughout the system using a bead recovery unit. Drill string drag is the incremental force required to move pipe up or down in the hole, and torque is the force required to rotate pipe. The magnitudes of torque and drag are related in any particular well, and high drag forces and excessive torque loads normally occur together. There are a number of causes for excessive torque and drag. They include:tight hole conditions;sloughing hole;key seats;differential sticking;cuttings buildup because of poor hole cleaning; andsliding well bore friction. With the exception of sliding friction, these causes are associated with problem conditions in the well bore. Although all of these conditions can occur in horizontal wells, the primary source of torque and drag in a horizontal well with good hole conditions is sliding friction. The ability to alleviate sliding friction using co-polymer beads has proven to be extremely beneficial in horizontal drilling and workover operations, including standard pipe and coiled tubing. Sliding Friction Normal contact force and the coefficient of friction between contact surfaces are the two factors that affect sliding well bore friction. Another factor, capillary attraction, must be considered in open hole situations. Capillarity is described as the relative attraction of the molecules of a liquid where it is in contact with a solid. The relative attraction of molecules leads to a force of adhesion between a solid and a liquid. The wallcake of a well bore will exert very strong capillary attraction forces on a drill string when it comes in close contact with the drill string. This is explained by the fact that the wallcake or mudcake is composed of very small particles of clay, barite, sand, or other matter, and these minute particles will have considerably more surface area exposed for wetting by liquid than would larger particles in the same section of mudcake. The smaller the particles, the more surface area exposed for liquid wetting, thus the greater the attractive capillary force exerted. The capillary attractive force could lead to the drill string adhering to the wallcake, creating torque and drag. The beads, having a larger particle size than the solids in the wallcake, reduce this adhesive force.

The capture of groundwater by horizontal wells (HWs) is an old but often overlooked technique. Practically all modeling techniques available in groundwater hydrology have been applied to HWs. This work compares analytical models with field data and investigates the influence of nonuniform screen inflow. The usefulness of a vertical well approximation is studied. A new MATLAB application, HORI, is presented for common analytical models. Analytical methods are found to reproduce drawdown around two radial collector wells (RCWs). Beyond the direct vicinity of the caisson, in particular, drawdown around an RCW can be approximated with a vertical well model.

This paper investigates the transient pressure behavior of selectively completed horizontal wells. A new solution in Laplace space is presented and asymptotic approximations are derived. Computational issues are also addressed. Flow characteristics of sectionally completed horizontal wells are discussed and the information that can be obtained from the analysis of pressure and derivative responses during various flow regimes are documented. It is shown that the solutions existing in the literature cannot completely describe the essential features of flow toward a sectionally completed horizontal well.