A Prediction Model of Casing Exterior Wear During Casing Running

With the development of drilling technology and reinforced exploration and exploitation of unconventional reservoirs, there has been a great increase of complex wells. Meanwhile, however, consequent casing wear is and will continue to be a serious problem that causes enormous economic losses and many safety issues. The purpose of this paper is to find out the mechanism of casing wear and establish casing wear prediction model. Casing wear experiment was carried out to study the effect of contact force, rotation speed, and casing grade on wear depth. Meanwhile, wear coefficients under different working conditions were obtained through the normalizing of data. With the extensive research of downhole drag and torque calculation method, a contact force calculation model was established. Through the combination of crescent-shaped model and wear-efficiency model, the past complicated casing wear prediction models and confusing empirical formulae were greatly simplified. Therefore, the wear volume and depth of the casing string can be accurately predicted. Finally, a prediction software was developed to predict downhole casing wear of oil and gas wells. Comparison with the field data confirmed that the established model and software had enough accuracy to help predict and analyze casing wear at field.

Casing wear is often a problem in deep wells where doglegs and large tension loads on the drill string combine to produce high lateral loads where the drill string contacts the casing. Casing wear can result in blowouts, lost production, and other hazardous and expensive problems. A mathematical model which describes casing wear in terms of hole geometry, casing/tool-joint material, mud system, and drilling program, has been developed and verified. Over 300 laboratory wear tests have provided wear factors which allow the model to be applied to a wide range of drilling situations. The model has been incorporated into a computer program, CWEAR. The prediction of dogleg severity and casing wear is seriously compromised by directional surveys in which the station spacing is 100 ft or greater. Through the laboratory test program, means to reduce casing wear rate have been demonstrated and applied in the field. Mud lubricants, tool-joint materials, pipe protectors, and casing materials and internal coatings have all been examined as possible means to reduce casing wear. Some mud lubricants significantly reduce frictional drag; others do not. Because a mud lubricant significantly reduces frictional drag does not imply that it will also reduce the casing wear rate. Newer, proprietary tool-joint coating materials have proven effective in reducing casing wear, while continuing to protect the tool joints in open hole. Pipe protectors have proven to be one of the better means of reducing casing wear. Laboratory experiments have demonstrated severe operational difficulties of these protectors. Several of the protector manufacturers are now engaged in development programs to improve their products. Inadequacies in the available methods of measuring casing wear in the field have been demonstrated. As a result of this work, at least two new casing wear measurement tools are under development.

A dynamic stiff string torque and drag (T&D) model is presented that assumes steady state motion of the drillstring as its basis for calculations. Results are compared to previously published T&D models that are based on static equilibrium. The novelty of the new dynamic model is the ability to solve T&D operations of the entire drillstring from bit to top drive in reasonable time using standard engineering computers. The new approach is based on a 3D dynamic model of drillstring and BHA in an elastic borehole. It considers bending stiffness, torsional stiffness, contact forces, and friction with localization of contact points. A numerical method is described that has proven to have excellent convergence. Complete governing equations are provided and the method is described in detail to permit readers to replicate results. The dynamic model is compared to two static stiff string models. Comparisons are also provided for three conventional soft string models including the Lubinski-Paslay-Cernocky bending stress magnification factor. Three field case studies are presented for horizontal wells. One well is short radius with dogleg severity over 50 deg/100 ft and two wells are unconventional shale wells with doglegs up to 15 deg/100 ft. Predictions for surface torque and drag up and down for the new dynamic stiff string model are compared to the static stiff and soft string models. In many situations modeled the top-level results for surface torque and drag up/down are close enough for all six models to be within the uncertainty range associated with the commonly used, lumped-parameter friction factor. However, some major differences in hook load for sliding and slack off operations are observed, which are shown to be caused by differences in location and magnitude of contact force between the drillstring and wellbore. Further, significantly lower surface torque is predicted by the new dynamic stiff string compared to other models for one case history because of lower contact forces in the vertical section of the well. In fact, the key finding of this paper is that major differences are observed for contact forces for the new dynamic stiff string model compared to all five other models, including the two static stiff string models. These differences in contact forces are most significant when the drillstring has helically buckled or when doglegs in the wellbore are high. Contact forces have a large impact on local stress behavior, which is important for predictions of casing and drillpipe wear, drillstring fatigue, and failure points in the drillstring. Although several previous papers have published stiff string models there is no industry standard formulation. The main problem holding back the development of an industry standard stiff model is perhaps the complexity of the numerical algorithm and substantial running time. To address this problem, some previous stiff string models account for bending stiffness of the drillstring but not for radial clearance while others appear to model only portions of the drillstring as stiff. The new stiff string model accounts for bending stiffness and radial clearance for the entire drillstring while still giving reasonable computational times. For stiff string models the advantage of using a dynamic approach to solve the steady state position of the drillstring is mainly related to superior convergence of the numerical algorithm compared to static stiff string models because calculation of contact points is faster.

Matrix acid stimulation in carbonate formations can often be vital to remove formation damage post drilling and achieve a more uniform production profile. Reaching well total depth (TD) is critical for an effective treatment in extended reach wells (ERWs) completed with an electrical submersible pump (ESP). The ESP completion with minimum restriction of 2.44-in. limits the coil tubing (CT) and downhole tools size. Hydraulically powered CT tractors are an ideal solution to pull the CT to TD (Saiood et al. 2018). The completion minimum restriction only allows for 2-in. CT with 2-1/8-in. OD hydraulically powered CT tractors and a maximum pulling force of 3,200 lbs. Pre-job CT design-aided simulations predicted the 2-in. CT size and a 2-1/8-in. CT tractor would not reach well TD due to unfavorable trajectory and therefore potentially jeopardizing a successful stimulation treatment. An alternative method is to utilize 2-7/8-in. CT combined with a 3.5-in. hydraulically powered tractor to conduct matrix acid stimulation prior to installing the upper ESP completion with restricted ID. This alternative arrangement allows for a maximum pulling force of 9,200 lbs, ensuring a greater reach in ERWs and effective treatment. It also tolerates higher pumping rates with 2.875in. CT (up to 5 bbl/min as compared with 2 bbl/min for 2-in. CT), reducing the exposure time of acid on surface, reaching optimum rates faster creating favorable wormholes in the carbonate formation and reducing the pumping operation time by up to 50%. Matrix acid stimulation is then completed with the drilling rig still in position post drilling operations. Thereafter, the upper ESP completion with restricted ID is installed. This engineered solution provides an alternative for CT interventions in extended-reach horizontal wells featuring completion restrictions, where the main challenge is to maximize the reach for optimum stimulation. The approach of combining the 3.5-in. hydraulically powered tractor with 2.875-in. CT pipe successfully enabled effective stimulation of the openhole section to a 27,000-ft. TD in a challenging downhole environment.

Young Technology Showcase As oil reserves mature around the world, oil companies look to improve the recovery of existing assets and to tap into unconventional reserves such as shale gas and tight gas. Coiled tubing (CT) and jointed tubing (JT) have progressed to larger sizes and premium material grades to adapt to these new and extended applications. However, some situations, such as long horizontal or ultradeep wells, remain where either the CT or JT is unable to provide the required reach efficiently and safely. Combining CT and JT can bring the flexibility of CT to extended-reach horizontal wells. Typical well intervention operations present several challenges, including equipment and reel availability, transportation issues, achievable flow rates, and the ability to reach the target depth of the well. CT is prone to sinusoidal buckling and eventual lockup in deviated and horizontal wells. This means that friction-reducing agents or mechanical aids such as tractors may be necessary to reach target depths. Smaller CT reduces the flow rate that can be achieved and requires higher horsepower to overcome fluid friction. JT, on the other hand, is larger and heavier than CT but requires constant making and breaking of connections during trip in and trip out, which requires redundant safety measures and reduces the effectiveness of downhole operations. In shale plays, operators have determined that laterals in excess of 10,000 ft and more than 30 fracturing stages are necessary to maximize production and achieve the desired return on investment. These wells are challenging to complete using only CT. PowerReach Service Boots & Coots, a Halliburton service, developed PowerReach, which combines CT and JT to form a hybrid string that offers the best of both. The resulting string allows for greater depth for long horizontals, high flow rates when using larger CT, and a smaller equipment footprint. The PowerReach system consists of JT at the bottom and CT on top to have the stiffness and weight of the JT at the bottom of the string and the freedom to move the CT portion on top without making connections. The length of CT depends on the length of the lateral or the distance from the first to the last section being treated. This ensures that the string can be moved freely without making a connection. Fig. 1 shows the setup of a hybrid unit on location, including a reel trailer, rig assist unit, and tower with tubing guide.

Drag and torque calculations for horizontal wells simplified for field use : Oil Gas J V89, N17, 29 April 1991, P49–56

An appropriate clearance is required between mating gears for effective power transmission. In the present work, the effect of radial misalignment on mild wear of spur gear is modeled and simulated. The changes in the gear tooth contact geometry due to progressive wear have also been accounted in the model. The simulation results show that in the pinion dedendum region, pressure angle increases, while the contact pressure and wear depth decrease with increase in number of wear cycles. As far as the effect of radial misalignment is concerned, contact pressure decreases and wear depth increases with the increase in misalignment. In the pinion addendum region, pressure angle and wear depth increase with the increase in wear cycles, while the contact pressure and wear depth decrease with the increase in misalignment. The pressure angle and pitch point change from initial 20° (23rd pitch point) to 20.95° (26th pitch point) and 21.86° (28th pitch point) due to 0.5- and 1-mm radial misalignment, respectively. The wear depths after 50,000 wear cycles are − 1.32 × 10−2 μm, − 3.33 × 10−3 μm and − 4.39 × 10−4 μm at 23rd, 26th and 28th pitch points, respectively. The effect of radial misalignment on backlash, pressure angle, pitch point, contact ratio, double tooth contact region and speed ratio is also discussed.

This paper addresses the various aspects of torque and drag problems encountered in drilling extended-reach wells. It discusses how to use torque and drag calculations and measurements to plan long-reach well profiles, to execute drilling operations that minimize torque and drag effects, to monitor hole cleaning, and to plan jarring operations.

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 91854, "Understanding Torque and Drag: Best Practices and Lessons Learned From the Captain Field Extended-Reach Wells," by G. Rae, SPE, Chevron Upstream Europe, and W.G. Lesso Jr., SPE, and M. Sapijanskas, Schlumberger, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February. Torque and drag (T/D) analysis was used for successful extended-reach drilling (ERD) in the Captain field in the North Sea. The tactics used in overcoming issues such as drill length and the associated risk are explained. The applicability of available T/D-reduction technologies and why many of them were eliminated as possible solutions reinforced the criticality of good T/D analysis on this project. Introduction The Captain field is in the U.K. sector of the North Sea, approximately 81 miles northeast of Aberdeen, in a water depth of 369 ft. Because of the high viscosity and low temperature of Captain oil, long horizontal wells are required to drain the reservoirs effectively (Fig. 1). Although the field was discovered in 1977, it was not until 1995 that appropriate technology was available and development approval was received. The field was developed as a phased installation with two drilling centers tied back to a central floating production, storage, and offloading vessel. Before starting the Captain subsea development, 29 directional wells were drilled in the first, or Area A, development of the Captain field. The requirements of the subsea, or Area B, development were demanding. These were factored into the rig selection and subsequent drilling specification. The Captain sands are shallow, at approximately 3,000 ft true vertical depth (TVD), and soft. The reservoir is thin but prolific. Geosteering or precise directional control in horizontal sections was necessary. The completion design required a 250-ft straight section (dogleg severity less than 1.0°/100 ft) no more than 350 ft TVD above the reservoir. This section is where the submersible pump would be placed. The design also dictated that the directional build rate shallower than this pump tangent be less than 4.5°/100 ft. The wells would be drilled with water-based mud (WBM) for environmental considerations. A WBM system also was necessary in the horizontal sections to achieve inflow-performance requirements.

This paper studies tubular buckling in curved wellbores (such as the build section of horizontal wells) and its effect on tubular “lockup” in horizontal or extended-reach wells. New buckling load equations are derived to properly predict tubular sinusoidal and helical buckling in such wellbores. The results show that the buckling loads to initiate sinusoidal and helical buckling of tubulars in curved wellbores are usually much larger than those in straight wellbores. This is because the curved wellbore tends to hold the axially compressed tubular against the outer-curve side of the wellbore. The tubular becomes less easy to buckle until higher axial compressive loads are applied. Less tubular lockup risk is then predicted for tubulars in horizontal or extended-reach wells by using the new buckling load equations. The new buckling loads in curved wellbores agree with those in straight wellbores when wellbore curvature approaches zero. Small-scale laboratory experiments also confirmed these theoretically derived buckling loads.

The effect of 200 days of cyclic weathering test (CWT) and 1,000 h of salt spray test (SST) on the performance of polyurethane (PU) coating was investigated. A 200 μm coating was applied to a composite and cured before CWT and SST ageing studies. CWT was conducted in ten cycles (each cycle: −40°C for 5 days, 70°C for 5 days, 40°C and 90% RH for 5 days, and salt fog for 5 days). Initial water immersion tests concluded that the coated specimens have 37% less water absorption than uncoated specimens. The degradation behaviour of the coating was evaluated by measuring pull-off adhesion strength, critical load from the scratch test, and wear depth from the pin-on-disk test. Similarly, the surface characteristics of the coating were studied by SEM, gloss value, and contact angle. CWT ageing caused a decrease in gloss value (93–78 GU), pigment content (18–8 wt%), contact angle (92–70°), and an increase in wear depth at 20 N of applied load (45–200 µm). Similarly ageing also decreased the pull-off adhesion strength to 6.77 MPa (CWT) and 7.93 MPa (SST). CWT and SST also decreased the thermal stability by 11–13°C, considering 5 wt% loss and tensile strength of the coating from 42 to 29 MPa. The damage to the composite substrate was not significant due to prolonged exposure periods under CWT and SST, though the damage was noted in PU coating, like increased surface roughness and wear depth.

Nanoperiod multilayered films were deposited by controlling the time the substrate was positioned opposite each of the graphite and boron nitride semicircular targets. The wear depth of the 4-nm-period multilayered film is the lowest of all the sliding cycles; therefore, the wear resistance is clearly improved for a 4-nm-period layered film. To clarify the reason why the wear resistance of these multilayered films increases, the wear properties of the load conditions under which the wear increases atomically were evaluated by varying the number of sliding cycles. The wear depth increases with increasing the number of sliding cycles. The weardepth increase rate of the 2-, 4- and 8-nm-period layered films is almost zero at a 1, 2, and 4 nm wear depths, respectively. This wear depth corresponds to the thickness of the interface of each carbon nitride [C-N] and boron nitride [B-N] layer. At both edges of the wear scar, short steps of layered depth were observed in the half-thickness of each period-layered film. These results indicate that the wear resistance increased because of the prevention of fracture growth at the interface between B-N and C-N layers in the case of multilayered films. To realize single-layer processing, the processing properties dependencies of the load and sliding cycles were evaluated. Under suitable conditions, the processed depth corresponds to the depth of each C-N and B-N layer. As a practical application of this newly developed fabrication technique, three-dimensional nanometer-scale profiles, such as 300 nm × 300 nm square, lines and spaces with 100 nm periods and three-step grooves were fabricated.

The influence of the particle size of fillers on the frictional wear properties of dental composite resins has been investigated. Five kinds of silica fillers with mean particle sizes of 0.5, 3.3, 4.3, 7.9, and 15.5 μm are used in this study. The filler volume is kept constant at 70 wt%. The coefficient of friction between the abrasive and the specimen was determined by a frictional wear device employing a rotating wheel. After the test, the wear depth was measured by a surface profilometer and the wear surface was observed by FE-SEM. The results demonstrate that the coefficient of friction and the wear depth increase with an increase in the particle size of the filler of composite resins. In addition, a linear correlation between the coefficient of friction and wear depth was found.

SummaryHorizontal wells are designed to have smooth (straight), curved, and lateral sections. However, the actual drilled path usually suffers from unwanted undulations from the planned well trajectory known as wellbore tortuosity. Wellbore tortuosity can slow the drilling penetration rate, aggravate drillstring vibration and buckling, complicate the casing and cement job, and lead to inaccurate wellbore position. This paper presents a validated computational fluid dynamics (CFD) model to investigate the impact of wellbore tortuosity on hole cleaning. The Eulerian-Eulerian approach is used to simulate solid-liquid laminar flow in annular geometry using polyhedral mesh. Then, the impact of wellbore tortuosity on cuttings accumulation, annular pressure loss, and fluid velocity was investigated and compared with the flow behavior in a straight horizontal well. A parametric analysis of spiral period length, spiral amplitude, drillstring rotation, flow rate, annular eccentricity, drilling rate of penetration (ROP), and cuttings size was conducted to assess their influence on cuttings transport in spiral tortuous holes and their relative magnitude to other design or operating factors.Simulation results show that polyhedral mesh is an optimum meshing technique for spiral profile geometry. Wellbore tortuosity aggravates hole cleaning in lateral sections based on the length of the spiral period and/or the spiral amplitude. Reduction in cuttings velocity was observed in the top part of the spiral geometry (crest), causing large deposition of cuttings in this area compared to the spiral lower part (trough). Drillstring rotation from 0 to 200 rev/min is the critical range for efficient hole cleaning in spiral geometry. Cuttings size can improve cuttings accumulation if the particle size is larger than the viscous layer located near the bed velocity profile. The drilling ROP and annular eccentricity aggravate cuttings accumulation and bed deposition in a spiral hole, similar to what is normally observed in straight horizontal wells.

Advances in drilling and well construction technologies have enabled extended-reach horizontal and multilateral wells to increase reservoir contact and improve recovery. Completion systems with passive inflow control devices (ICD) or intelligent wells are used to optimize and control inflow from the compartments or laterals. ICD completions are passive systems with torturous paths or orifices designed to choke back inflow from dominant zones and equalize influx along the wellbore. ICDs combined with openhole packers provide very fine compartmentalization of the open hole and it is common to have completions with 40 inflow compartments in some extended-reach wells. ICD completions require well intervention to close zones with high water or gas. Intelligent completions, on the other hand, have downhole valves that can be remotely operated from surface. The requirement for downhole control lines and penetrations at the wellhead and packers has limited the number of downhole valves to a maximum of six in a well. This limitation excludes a significant number of applications where greater compartmentalization can yield superior well performance. The industry has recently developed innovative completion systems that increase the number of surface-controlled downhole valves while minimizing the number of downhole lines. These technologies improve completion design while overcoming limitations like the number of control lines, feedthrough ports on packers and wellhead. Saudi Aramco has recently installed an all-electric intelligent completion with 8 downhole active flow-control devices (AFCD) controlled via a single downhole control line. This installation is currently the world record for the highest number of inflow control valves installed for an intelligent completion. This paper presents details of technology development, evaluation, completion design, installation and in-well testing of the all-electric intelligent completion system in a multilateral well. The paper presents the novel completion design with redundancies, system components, advantages of the chosen technologies and the completion method. The section about the planning phase of installation highlights steps taken to ensure successful execution of the job while minimizing operational risks associated with the deployment of the new technology. Finally, the execution phase of the installation is presented with special emphasis on procedures and actions during installation to improve operational efficiency and minimize health and safety (HSE) risks. Thorough design, planning and execution of the job yielded the successful installation of an advanced and complex intelligent completion system in an efficient and safe manner. All-electric intelligent completion systems capable of controlling multiple downhole valves are anticipated to increase well life and recovery through improved downhole monitoring and control. This system can control as many as 27 AFCDs on a single electric control line.