Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
Shale drilling for both natural gas and hydrocarbon liquids has increased dramatically in North America over the last several years. Shale oil and gas deposits are known to exist all over the globe including Australia and the rest of the Asia Pacific. This paper discusses the requirements for drillpipe in shale drilling applications along with a review of some of the challenges and problems associated with the drillstring in these critical applications. Most wells are horizontal with long departures. Typical wells in the Balkan Shale are 17,000 ft MD, 11,000 ft TVD with a 6,000 ft horizontal reach. Drilling these wells puts huge demands on the drillpipe and rotary shoulder connections and pushes the drilling equipment and rig crews beyond the requirements of typical onshore well construction projects. Many, if not most, of the shale wells require advanced design, double shoulder connections (DSC) on the drillstring to provide the enhanced torsional strength and streamlined connection dimensions required to effectively drill these prospects. The paper presents connection design solutions along with considerations for safe and efficient running procedures. Although, the advanced DSCs are designed to be transparent to normal drilling operations, compared to standard API connections, some problems have been encountered. The paper addresses these running and handling issues and provides guidelines to mitigate these problems. Excessive tool joint and drillpipe body wear have also been encountered in several shale plays. This is discussed, along with recommendations to limit wear. Stick-slip has created drillstring problems on several wells. Stick-slip can cause damage to the drillpipe and, in the extreme, downhole connection back-offs have occurred. The paper looks at aspects of case histories to illustrate these issues and provides lessons learned to improve shale drilling operations in North America, the Asia Pacific and other regions of the world.
Horizontal directional drilling combined with multi-stage hydraulic fracturing have created a robust drilling environment for exploiting shale natural gas and hydrocarbon liquids throughout the U.S.A., see Figure 1. It is also well known that shale oil and gas deposits are also present throughout the rest of the world including Australia, New Zealand and various regions of the Asia Pacific, see Figure 2. Expectations are strong that more shale and other unconventional sources will be explored outside of the U.S. as new sources of hydrocarbon energy resources are required to meet increasing worldwide demand. Shale drilling activity in the U.S. has increased dramatically over the last several years. Shale drilling applications can be very demanding for the drilling rig, equipment, crews and technical professionals involved in the endeavor. The learning curve has been steep and there are clearly more technical challenges to be addressed and overcome as more areas are explored. Of course, there is a great deal of variation between the characteristics of different shale fields and not all fields create the same intensive challenges or technical hurdles. Nevertheless, a great number of the fields currently being explored and produced offer significant challenges. In many of the fields the gas and/or liquids are located at relatively deep TVD's; with TVD's from 10,000 ft to 14,000 ft not being uncommon. As mentioned above, the wells generally include a horizontal section that can extend up to 6,000 ft and beyond. A typical shale well schematic is depicted in Figure 3. The wells can also have high bottom hole formation temperatures that in some cases approach 375 °F. In many areas the formations are highly abrasive creating friction and wear related issues.
Drilling the hard/abrasive Travis Peak/Hosston and Cotton Valley formations in East Texas/North Louisiana creates a distinctive challenge for polycrystalline diamond compact (PDC) bits. Conventional PDC cutters fail quickly due to abrasive wear/spalling and/or delamination of the diamond table. Most bits are typically pulled in poor dull condition graded 1-2-WT or worse. The situation has caused stagnation in PDC performance and limited additional gains in total footage and rate of penetration (ROP). Recent scientific studies have indicated that thermal fatigue of the diamond table is the main contributing factor leading to cutter failure and is restricting further advancement of PDC drilling in East Texas and other hard and abrasive applications. To improve cutter performance the industry must:
1. Manufacture a cutter to resist abrasive wear and retain a sharp edge for an extended amount of footage
2. Reduce/maintain temperature at the cutter edge to minimize thermal fatigue
To accomplish the objectives, engineers refined and implemented several new processes to increase abrasion resistance and maintain temperature at the cutter tip. This technology platform includes:
1. Enhanced High Temperature/High Pressure (HTHP)sintering process
2. Refined post-pressing process to improve thermal stability
3. Optimized hydraulics to maximizing cutter cooling
In laboratory experiments, the next generation O2 cutter has demonstrated approximately 15% improvement in resistance to abrasive wear compared to the previous generation of premium cutters (O1). Laboratory tests also confirm that optimizing cutter cooling has enhanced the life of the new shearing element. In East Texas field tests, PDC bits equipped with the new cutter and optimized hydraulics have achieved an average ROP increase of approximately 25% while producing improved dull bit condition. These new technologies are expected to have a positive economic impact in the East Texas/North Louisiana Haynesville shale play and in other hard and abrasive applications worldwide.
Casing integrity is extremely important to downhole zonal isolation and preventing well instability. The reduction of casing strength not only occurs in directional drilling, but is also observed in vertical drilling with a slight deviation angle. Deteriorated casing in most hydrocarbon wells is reported from the onset of casing wear by the presence of friction force during the rotation of drillpipe. The friction on the casing wall causes the reduction of casing strength. Furthermore, the combination of corrosive drilling fluids with the rotation of drillpipe could dramatically degrade the casing strength. Although casing burst and collapse strength have been emphasized by many researchers, little research has presented the mechanical response of the worn casing. The studies that do exist on casing wear are not relevant for field applications because they do not consider the effects of high temperature and the surrounding formation. Therefore, it is urgent to obtain a proper stress profile of worn casing in order to reveal the true downhole information.
Based on the boundary superposition principle, we propose an analytical solution for the worn casing model that accounts for the contribution of thermal stress. We focus on the stress evolution in worn casing from the effects of high temperature and the confining formation. The predicted results show that the higher thermal loads largely increase the stress concentration of the worn casing, subsequently weakening the casing strength. The finite element solutions indicate that the radial stress in worn casing is not impacted as much as the hoop stress. The remaining part of the worn casing is subject to compression failure, along with an increase of the burst pressure or the elevated temperature.
The flow assurance aspects of all subsea projects have a major contribution tothe pipe design, field layout, choice of lifting equipment (subsea-pump or airlift), power requirement and system operability. The context of deepwatermining pushes the design theories beyond the existing application cases due tothe significantly larger particle size combined with small diameter riser andjumper including wave shape to accommodate vessel motions and excursionrequirements. In order to correctly assess pressure drop and erosion rate closeto real flow conditions, TECHNIP and GIW have built a large scale experimentalbench operated at the same flow condition as forecasted for the deepseaproject. This large scale test is using an innovative method to allow thereproduction of realistic erosion rate in the pipe by preventing the solidparticle to be eroded when looping through the pump.
The current paper summarizes the findings and results from this large scaleexperimental set-up, testing concentration from 10% to 45%, velocities from2.5m/s to 5.5m/s in an 8" flexible pipe with equivalent rocks particles.
As described in (Espinasse, 2010), Technip is supporting an internal R&Dprogram that should allow the understanding of critical parameters essential tothe design and operability of a subsea mining system. Within this R&Dprogram, an extensive study of the abrasion and erosion mechanism inside theflowline is needed to:
• Understand the inner pipe wear mechanism function of flow conditions
• Define the proper flowline pipe material providing the best compromisebetween wear resistance and pipe cost.
• Define a procedure to evaluate the lifetime duration of the flowline pipeduring operations to schedule inspection and maintenance.
To capture and understand the abrasion during subsea mining operations, Techniphas setted-up a full scale test with the help of GIW. In addition of tacklingflowline wear issues, this test is used to validate at large scale thehydraulic modeling exposed in (Parenteau, 2010) and (Parenteau, 2011).
STATE OF THE ART
The particularity of subsea mining is to transport large and dense particle inrather small diameter pipe compared to what the industry of slurry transport isused to. Subsea Mining Partcicle size disctribution can range from 1 mm to60mm. Crushing experience conducted in (B. Waquet, 2011) indicated that atleast 50% will exceed 25mm and more than 25% of the solid will exceed 50mm[Figure 1]. The particle densities range from 2500 kg/m3 up to 4000 kg/m3. Pipediameter will range between 8" to 10", and evolving into wavy shapes.
ABSTRACT Anytime sucker rods contact the inner diameter of production tubing in corrosive wells, wear accelerated corrosion will result. The resultant damage is likely to be greater than the sum of the two factors acting individually. Experience tends to agree that minimizing the corrosion component with corrosion inhibitors minimizes the damage, and that continuous application of the inhibitor is more beneficial than batch application. This paper follows laboratory development and field testing of a batch applied corrosion inhibitor designed to have added benefit for this task. In the laboratory linear polarization resistance evaluated inhibition and standard lubricity tests evaluated wear characteristics. Corrosion coupons, manganese ion in the water from this sour field, and failure records evaluated field performance. Coupons detect the corrosion component, and manganese ions reflect total corrosion-plus-wear occurring in the well. The ratio of these to measurements before and after application evaluated success prior to any failures occurring. INTRODUCTION Exact details of the mechanism of wear accelerated corrosion are certain to be quite complex. 1 Just wear itself and lubrication are complex enough. 2, 3 Electrochemical corrosion due to dissolved gases and volatile organic acids in the oilfield has been the subject of many studies. 4 Many times an active wear area in a corrosive media becomes anodic to the film area, giving rise to galvanic corrosion acceleration. 5, 6 Mechanistic similarities probably exist for erosion accelerated corrosion. 7, 8 Rather that explain all the facets of the mechanism, this paper outlines attempts to minimize wear accelerated corrosion with corrosion inhibitors. Earlier studies have shown that this effort can provide benefits. 9, 10 The reason that sucker rod strings sometimes contact the inner diameter of production tubing can be due to crooked zones in the hole, or to intentionally deviated holes.
Wells are now routinely drilled both in deepwater and on land to depths that were previously considered impossible. In these environments, casing design is critical to safely and successfully drilling and producing wells, and unexpected casing wear can result in significant costs or even the loss of a well. As part of a successful casing design strategy, the engineer must assess the maximum permissible casing wear required to maintain casing integrity. Then, steps must be taken to ensure that casing wear thresholds are not exceeded.
Casing wear models use the number of drill string revolutions and contact force between the drill pipe and casing to calculate wear. The contact force is calculated using the dog-leg severity within the well, with the maximum dog-leg severity often determining the location and extent of the most severe casing wear. There is often a large discrepancy between predicted and actual casing wear because of survey quality and inaccurate estimates of dog-leg severity and total revolutions. These discrepancies result in predictions of contact force and drill string revolutions that are in error by 50% or more.
To improve the accuracy of casing wear models, an extensive database was created from a wide variety of wells with measured depths greater than 13,000ft. The database results in a statistically based model for determining dog-leg severity within vertical, build, and tangent sections, as well as total drill string revolutions at various levels of confidence to bound average and maximum expected contact force and casing wear.
Case histories compare measured wear with predictions of casing wear based on original well data and the statistically based model. The case histories also demonstrate the effect of various drilling parameters on casing wear, and evaluate the effectiveness of non-rotating protectors in preventing casing wear.
The goal of this project was to more accurately quantify casing wear risk by improving casing wear analysis accuracy. To do this, data from a large number of wells was analyzed to generate probabilities for dog-leg severity in common well types and also correlate those to actual backmodeled casing wear factors. The results will allow an engineer to analyze what the expected casing wear might be for an average (P50) horizontal well, and then evaluate the maximum expected wear for a 1 in 10 case (P90), 1 in 20 case (P95), or 1 in 100 (P99) case.
All casing wear software, and torque and drag software as well, use a directional survey to determine the side force or contact force between the drill string and wellbore. These points within a directional survey can be a representation of a planned well path, or it can be taken from actual downhole measurements. The survey points are then connected into a single line representing a best approximation of the wellpath with the information given.
Orazzini, Simone (ENEL Italy) | Kasirin, Regillio Sarijo (Smith Bits) | Ferrari, Giampaolo (Smith Bits, A Schlumberger Company) | Bertini, Alessandro (Smith Bits, A Schlumberger Company) | Bizzocchi, Isabella (Schlumberger Italiana SPA) | Ford, Robert J. (Schlumberger) | Li, Qingxiu (Smith Bits, A Schlumberger Company) | Zhang, Ming (Smith)
Geothermal energy has been use for centuries to satisfy general heating requirements. The modern geothermal plant is powered by production wells drilled to a source rock to produce steam at the surface. Depending on the location and depth, source formation temperatures vary.
In Italy, the operator must penetrate very hard and abrasive sediment and metamorphic formations to access steam in the granite basement formation. Historically, this was accomplished with a tungsten carbide insert (TCI) roller cone bit (RC). Standard geothermal bits and components, including grease and elastomer seals, are adequate for temperatures up to 150°C (302°F). Beyond these temperatures, the bit's internal components and lubricating material can degrade causing bearing failure limiting on-bottom drilling hours. In the application, the bottom hole temperature is approximately 180°C (350°F) and in some instances it can exceed 280°C (536°F). The extreme heat reduces on-bottom drilling hours leading to multiple bit runs/trips that drive up development costs. The operator required new roller cone technology that would endure the downhole environment.
To solve this challenge, a series of tests were conducted with temperature resistant elastomers and grease compounds in a controlled laboratory environment. The experiments resulted in a new line of roller cone bits equipped with an innovative bearing system that includes new proprietary composite elastomer seals with Kevlar® fabric and a proprietary high temperature grease formula. These innovations increased seal life, lubricity and load capacity at elevated temperatures for HT/HP applications.
The new geothermal bit technology has been run in the Italian application with outstanding results. Compared to standard roller cone products, the high-temperature bits have greatly increased on-bottom drilling hours while reducing total bit consumption and costly tripping for bit change out. Since successful development of the geothermal project is tied to reducing drilling costs, the new bit technology has significantly improved project economics. The authors will discuss development of the high temperature seal and grease compounds for drilling the granite basement source rock. They will also outline changes to the TCI cutting structure, field application, dull grades and bit performance data.
The Larderello area of central Italy (Figure 1) is geologically active and known for its geothermal productivity.1 The first evidence of organized use of the geothermal resource dates back to the 3rd century BC when the Romans used its hot sulfur springs for bathing. In 1817 a group of entrepreneurs led by Francois de Larderel used steam heated cauldrons to extract boric acid (H3BO3) from volcanic mud. The Grand Duke of Tuscany (Leopold II) was a supporter of Larderel's technique and in 1827 built a town for the factory workers named Larderello in honor of Larderel's contribution to the area.2
In 1904 an experiment using steam emerging from surface vents was used to run a rudimentary generator that produced enough electricity to power five light bulbs. It was the first ever practical demonstration of geothermal power. In 1913 the region's first geothermal power plant went into operation and by 1944 five geothermal generating stations were up and running with a combined capacity of 127 MWe.