bluuebunny/crossref_metadata_2025_split huggingface dataset:
Thailand Joint Development Project Delivers 200°C M/LWD Triple Combo: Eliminating Wireline, Driving World Class Efficiency and Slashing Days Per Well
Authors: Kleawyothatis T. , Pruimboom J. , Dendandome S. , Pisarnbut N. , Thipmongkolsilp P. 
Published: October 2018

Abstract
There is no longer a requirement to run wireline Triple Combo logs in deep, high temperature wells. A joint development project has successfully delivered the world's first high-temperature M/LWD Triple Combo suite rated for 200°C [392°F]. Results to date are compared with previous performance in the Gulf of Thailand (GoT).
The new suite required a ground-up redesign of printed circuit board (PCB) electronics in order to meet the temperature qualification criteria of 200 hours at 200°C [392°F], with a survivability of 210°C [410°F] for four hours. The suite's sensors were developed in two phases, each with four milestones, over a period of 36 months. Initial rigorous thermal qualification was followed by harsh thermal vibration qualification testing routines. Several PCB redesigns were required in order to finally pass this testing. Ultimately, five prototype triple combo suites of tools were delivered to Thailand, on time and on budget, for in-situ field testing.
M/LWD Triple Combo field trials commenced offshore in the GOT, in fields exhibiting some of the global industry's most demanding drilling environments with respect to high rates of penetration [and accompanying punishing levels of vibration], extreme temperatures and significant well complexity. Compared to adjacent platforms with similar wells in the most challenging field, the new suite, together with other drilling efficiency measures, played a pivotal role in helping to reduce average days per well over 50% a considerable improvement. To date, more than 475,000 ft [145,000 m] have now been drilled in 71 GoT wells using this Triple Combo M/LWD technology. Furthermore, the new high-temperature Triple Combo M/LWD tools have been one of several key contributing factors in establishing two notable drilling records: drilling the GoT's longest well at 17,559 ft [5,532 m] and the longest single-bit run in the production section at 8,952 ft [2,729 m], without any failures at a maximum temperature of 199°C [391°F]. The suite provides additional benefits such as the provision of real-time annular pressure while drilling.
With this feature, engineers can closely monitor the equivalent circulating density (ECD) an important parameter for avoiding kicks and losses at up to 200°C [392°F].
The proven step change in drilling efficiency arising from this joint development can be attributed to the elimination of temperature mitigation measures and Triple Combo wireline logging, the problems associated with acquiring the wireline data, and an overall improvement in drilling practices.
Unique Backup Cutter Layout Method Leads to Step Change in Bit Durability and Performance when Transition Drilling Through Hard Limestone Formations at High Inclinations
Authors: Vrnak Kyle , Boutot Franck , Anderle Seth 
Published: October 2018

Abstract
In the mature fields in Norway's North Sea, extended-reach drilling (ERD) well designs were implemented to reach distant reservoir target zones. Resulting from this change, the 12.25-in. overburden section, which drills through mostly shale with various hard and thin dolomitic limestone sections, had to be modified from a 5,000- to 7,000-ft vertical section to a 10,000- to 12,000-ft section at a tangent inclination anywhere from 35 to 70°. Drill-bit designs that used to drill the vertical overburden section consistently in one run currently require up to three bits to complete the modified tangent sections caused by excessive damage to the diamond cutting structure.
An extensive study into the offset ERD wells and corresponding bit dull conditions helped identify that the cutting structure damage originated from high-point load impacts to the shoulder of the bit while transitioning through the thin, hard dolomitic limestone formations; the damaged cutters were being tangentially overloaded. Through further bit modifications, it was determined that this type of damage could not be addressed using typical bit design modifications (e.g., increased cutter density, increased blade count, etc.); therefore, a unique design solution was developed and implemented.
This solution involved combining analytical simulations and a dull condition analysis to develop an improved method for using the backup cutting structure to support the high tangential loading on the primary cutting structure during hard, high-inclination transitions. In most dual-row cutting structure designs, the backup cutters are on the same radial position as their parent primary cutters and are underexposed, engaging the formation only at a specific depth of cut or after the primary cutters are worn down a certain amount. When positioned as such, the backup cutters do nothing to support the tangential loading on the primary cutters. By moving the backup cutters actively on profile with the primary cutters and offsetting them to their own radial positions, the backups could now actively support the high tangential loads occurring on the primary cutters when engaging the hard dolomitic limestone.
This simple but unique modification enabled the bit to handle the transitions and drill the entire next 11,000-ft+ ERD section in one run while also providing the fastest rate of penetration (ROP) to date, with an increase ranging from 30 to 40% compared to previous runs. The success has been repeated a dozen more times since, each time providing a new record ROP for an ERD section. The improved dull condition could also allow for more efficient designs in the future for further improvements to drilling performance. The successful reduction of tangential impact damage could have implications for various bit designs globally that incur a similar dull condition.
Operational Designs and Applications of MPD in Offshore Ultra-HTHP Exploration Wells
Authors: Yin Qishuai , Yang Jin , Zhou Bo , Luo Ming , LI Wentuo , Huang Yi , Sun Ting , Hou Xinxin , Wu Xiaodong , Wang Junxiang 
Published: October 2018

Abstract
The South China YQ Basin with 15 trillion cubic meters natural gas is typical of ultra high temperature-high pressure (ultra-HTHP) with the highest bottomhole temperature (BHT) at 249°C, the maximum bottomhole pressure (BHP) at 142MPa and the extremely narrow pressure window. Therefore, there are kinds of technical challenges during drilling there. In recent years, the managed pressure drilling (MPD) has been successfully applied in the basin with risks and well cost reduced instead.
The operational designs of MPD consist of three parts: the precise calculation of drilling fluid equivalent circulating density (ECD), the optimization of operational parameters and the well control. The first part includes four models: the wellbore temperature field model, the drilling fluid equivalent static density (ESD) model, the drilling fluid rheological property model and the effects of cuttings concentration on ECD. The second part is the determination of the two key operational parameters: the mud weight (MW) and the surface backpressure (SBP). The third part is the plans of three cases: downhole accidents, equipment failures and termination conditions of MPD.
The first part includes four steps: establish the instantaneous wellbore temperature model based on the convection and thermal conductivity theory by dividing the wellbore into five areas; establish the ESD model by considering the elastic compression effect of HP and thermal expansion effect of HT; establish the drilling fluid rheological property model based on the Herschel-Buckley model by considering the effect of ultra-HTHP on dynamic shear force, consistency coefficient and liquidity index; consider the effects of cuttings concentration on ECD based on the solid-liquid two-phase flow. The ECD model is established based on above models. The second part includes two steps: determine the MW based on the critical pressure constraint principle by the operational window simulation of different well depth and fluid volume; determine the SBP of pump-on and pump-off by considering the rated operating pressure of the equipment, the calculated pressure loss and the 0~1MPa higher BHP than formation pressure. The third part includes three steps: make the emergency measures against downhole accidents by well control matrix; make the emergency measures against the failure of equipment such as rotating control device (RCD); determine the MPD termination conditions such as drilling big cracks.
The MPD is successfully applied to X gas field featuring offshore ultra-HTHP. The casing structure is optimized from 7-8 layers to 5 layers and the well is drilled in the micro pressure window of 0.01~0.02sg without accidents. Additionally, the non-productive time (NPT) decreases by 60% and the well cost is obviously reduced. Generally, the MPD yields time and cost savings for tomorrow's market.
Process, People and Technology: Synergy Leads to Performance Improvement, a Case from South Iraq
Authors: Mee Michael , Dementyev Alexander 
Published: October 2018

Abstract
Operators and service companies alike gain from improvements in efficiency. However, many organizations fail to look beyond technology and in depth at all the minute processes that become part of drilling a well. Delving in to these processes, applying area appropriate technology and putting the right people in place to execute the workflow is not enough. Synergy between all three needs to take place.
This paper illustrates through examples and figures, how an integrated approach to engineering and operations focused on the incorporation of field appropriate processes, people and technology for a given area will lead to increased efficiency in drilling operations and improved HSE performance. Specifically, in Southern Iraq. The paper will focus on three areas.
First, people and process, what the proper level of expertise is and what continuous improvement processes were these people trained to use in the field and in the office? Even with the drive to mechanization and automation the drilling industry is currently heavily reliant on people and their input. People are unpredictable, putting the proper processes and workflows in place introduces some predictability and consistency to well delivery. Keeping these processes focused and minimized allows creative problem solving to still be of value.
Second, technology and process, the upstream oil and gas industry has been historically resistant to technology chances, but eventually adopting relevant technologies after an extended trial period. Using a defined process to evaluate technology (both software and tools) allowed this team to select area appropriate technology from the vast array of new technology available. On the other hand, there were times when legacy technology was best suited to the application in this field.
Last, integration processes, how was the above brought to bear on a project in South Iraq and how was it all blended together in such a manner as to produce a net ~40% improvement in overall well times? How should managers and team members treat integration? Where and when does the value of integrated processes begin to take effect?
This paper will discuss the methods used, the technology implemented, the processes designed to manage performance, and the results on the project will be laid out in further detail.
Cost and Operation Optimisation for Downhole Tractor Conveyance for Perforating in ERD Wells by Using Wireline Multistage Pressure Deployment System
Authors: Ibrahim M. Z. , Ibrahim M. M. , Findlay C. , Techanukul T. , Noor Hassim M. F. , Wongyaowarat K. , Ramli M. R. 
Published: October 2018

Abstract
The recent infill wells of MDE were drilled and completed with the most complicated architecture in CPOC. They were designed with high inclination reaching almost 87 degree and 2.6 ERD ratio in order to optimize hydrocarbon recovery from multi-stacked reservoirs within the area. The study, driven by cost effective initiatives, compared wireline tractor conveyed perforation (run in normal and reverse deployment modes) and coiled tubing conveyed perforation (again, run in normal and reverse deployment modes). The aim of this study is to provide the most efficient technique to achieve maximum hydrocarbon returns with low operational costs and minimum risks. The scope of this study includes consideration of well test requirement and net over gross ratio of perforation interval.
Four (4) options are feasible to complete these high inclination and long departure wells: wireline tractor-conveyed perforation (run in normal and reverse deploy modes); and coiled tubing-conveyed perforation (run in normal and reverse deploy modes). The analysis includes several factors such as different rig-up height, perforation depth accuracy, perforation flexibility, operation time, and tool requirement. Generally, the job executions begin by rigging up the perforating gun into wireline or coiled tubing conveyance, then running in hole to designated target depths.
The wireline tractor with reverse deployment and multiple-firing system was the chosen method, deployed for the first time in slim hole, high inclination and long departure wells within Joint Development Area (JDA), Gulf of Thailand. This conveyance method proved to provide a 68% reduction in numbers of runs, with cost reductions of 25% and 50% in operating day and operating costs respectively. Perforating operations in all three wells were successfully completed with 269 meters total perforation length. The tractor operated for a total distance of 94 kilometers which is considered as the longest tractor marathon in a campaign worldwide.
The utilization of tractors for this campaign is considered as a record breaking for the operators and contractors. As a result, the wells have been able to deliver the gas as expected and fulfill the nomination to buyer demand.
Investigation on Hydraulic Fracture Initiation and Propagation with LPG Fracturing in Shale Formation based on True Tri-Axial Laboratory Experiments
Authors: Zhang Ruxin , Hou Bing , Zeng Yijin , Zhou Jian , Li Qingyang 
Published: October 2018

Abstract
Traditional hydraulic fracturing requires lots of water and sand resulting in short fracture length and small SRV with a low production. However, a new waterless fracturing, called Liquefied Petroleum Gas (LPG) fracturing, is applied to stimulate shale formation effectively.
In order to figure out the mechanism of fracture initiation and propagation in LPG fracturing, four large-scale true tri-axial fracturing simulation experiments have been conducted on shale outcrops. Meanwhile, the effects of engineering factors, pump rate and fluid viscosity, on fracture propagation behavior in the shale formation are discussed.
The experimental results indicate that LPG fracturing not only activates discontinuities to form a complex fracture network, but also enhances induced fracture length to form a large SRV. Induced fractures have two initiation points, open-hole section and stress concentration point of wellbore wall, and have three main propagation behaviors, crossing, shear and arrest, dilation and crossing in shale formation. A low viscosity fracturing fluid activates discontinuities resulting in complex fractures, whereas, a high viscosity fluid would like to create some main fractures without opening discontinuities. Moreover, a high pump rate offers more energy for induced fractures to cross the discontinuities resulting in a long fracture length and large SRV. In addition, the anisotropic of shale formation and the existence of discontinuities cause signals attenuation, which increases the arrival time, resulting in location deviation of acoustic emission (AE) events in the AE monitoring. The pressure-time-energy curve, however, shows that the fracture initiation is earlier than the sample ruptured. That is, the initiation pressure is smaller than the ruptured pressure.
The experiments conducted in this paper prove that the LPG fracturing indeed has some advantages than traditional hydraulic fracturing, such as long fracture length and large SRV. And then, the research results provide the theoretical basis for the LPG fracturing operation in shale formation.
Evaluation of Novel Surfactant for Acid Stimulation and EOR Treatments
Authors: Bin Omar Abdulrahman , Al Moajil Abdullah A. , Al-Darweesh Sajjad , Al-Rustum Abdullah 
Published: October 2018

Abstract
This paper represents a study of the application of nano-surfactant in the acid stimulation and EOR operations. The performance of the novel surfactant was compared with commercial alcohol ethoxylate surfactants. Different acidizing additives were added to the surfactants under study to evaluate their behavior using surface tension measurements. A negative behavior of the nano-surfactant with corrosion inhibitor, H2S scavenger, and iron control and reducing agents were observed. Regardless of the effect of these additives on the surfactant performance, the nano-surfactant still provides a better performance overall compared to commercial alcohol ethoxylate surfactants. Interfacial tension experiment of the nano-surfactant with condensate samples was performed giving an average IFT of 8 dynes/cm at 160 °F.
Understanding Stress Effects on Borehole Acoustic Waves for Unconventional Shale Reservoirs
Authors: Lei Ting , Zeroug Smaine , Sinha Bikash , Bose Sandip 
Published: October 2018

Abstract
Acoustic velocities in many sedimentary rocks exhibit stress sensitivity. This behaviour has been validated through experiments, observed from field measurements, and is described by the acoustoelastic model. Inversion methods based on this model have been developed to characterize stresses, and provide the basis for non-destructive means to calibrate stress profiles. Observation of borehole sonic dipole dispersion cross-over signatures serve as an indicator of stress-indcued anisotropy – an effect that has been validated theoretically through 3D numerical modeling. Such modeling has been carried out for sandstone and cabonate rock and less so for shale rock. To understand the stress effects on sonic measurements in wells traversing unconventional reservoirs, we carry out simulations of the borehole sonic measurement in shale formations subjected to subsurface stresses.
To this end, we have developed and used a new 3D modeling code based on the finite-difference time domain scheme in a cylindrical coordinate borehole system. The linear and nonlinear elastic constants of shale core samples from laboratory experiments are used as inputs to the modeling. Synthetic waveforms are processed using a modified matrix pencil algorithm to estimate the borehole sonic mode dispersions and their sensitivities to the stress-induced anisotropy.
For a vertical well, our modeling results demonstrate new dispersion signatures associated with certain shale formations. The borehole flexural dispersions at the two canonical horizontal stress directions split at high frequencies whereas they overlay at low frequencies. The split at high frequencies is caused by near-wellbore stress concentrations and the overlay at low frequencies is owing to the typical shale laminated lithology. The modelled dispersion signatures were also observed from processing of field data acquired with both sonic and ultrasonic tools in a vertical well in a laminated unconventional shale formation. The ultrasonic tool measures compressional and shear slownesses azimuthally at radial depth of about 1 in. from the borehole surface. The presence of imbalanced stresses is confirmed in adjacent intervals from symmetric breakouts. In a 20-ft interval not exhibiting breakouts but surrounded by intervals with breakouts, the ultrasonic tool also measures the compressional and shear slownesses with an azimuthal quasi-sinusoidal variation caused by stress concentrations around the borehole. On the other hand, sonic waveforms recorded by cross-dipole measurements in the same interval show high-frequency splitting dispersions as reproduced by the modeling. Taken together, these results confirm the existence of a new sonic dipole signature caused by the subsurface stresses in vertical wells traversing unconventional shale reservoirs.
Foam Hydraulics Modeling for Sand Cleanout in Low Bottom Hole Pressure Wells
Authors: Rao Sai Sashankh , Antunes Morgado Nicolas , Kulkarni Kaustubh Shankar , Sun Huafei , Arnold Allen 
Published: October 2018

Abstract
As foam is significantly less dense than water, and it can have a rheology capable of holding sand, it is an attractive fluid for sand cleanout in completions of low bottom hole pressure (i.e. underbalanced) wells. However, predicting the behavior of foam can be technically challenging, and mobilizing equipment to perform foam operations can be expensive. The primary objective of this work is to demonstrate how a foam hydraulics model can be used to determine the feasibility of performing a foam operation for a given well and to maximize sand cleanout rate in wells where feasible.
Foam is a compressible fluid characterized by its quality (ratio of gas volume to total (gas+liquid) foam volume) and works as a stable fluid within a certain range of quality. Foam’s quality depends on its pressure. As pressure increases, foam’s quality decreases due to compression of gas in the foam. In this work, we make simplifying assumptions to develop a one-dimensional steady-state hydraulics model for foam flow through coiled tubing and then back up the annulus of deviated wells that contain a sand bed. The hydraulics model for foam captures foam’s compressibility, non-Newtonian rheology, non-linear hydrostatic pressure profile, friction pressure including slip velocity, the effect the geothermal gradient has on the foam, and the effect suspended sand has on the foam. We obtain results for the foam pressure and quality at various locations along the coiled tubing and wellbore annulus, as well as the time it takes to circulate foam through the coiled tubing and annulus. In more detail, we obtain results for the hydrostatic pressure and frictional pressure drop for different sections of the coiled tubing and annulus. The results show that an increase in foam quality (i.e. increased ratio of gas to liquid) results in a decrease in hydrostatic pressure (lighter foam) but an increase in the frictional pressure drop (more viscous foam), following experimental evidence. The bottom hole pressure of foam is a function of the hydrostatic pressure and frictional pressure drop in the annulus. Thus, as the foam quality increases, the bottom hole pressure can increase, decrease, or stay the same. The results bring out the non-intuitive behavior of foam and demonstrate how challenging it can be to control a foam hydraulics system. We compare our model predictions for the total pressure drop across the coiled tubing and annulus to field data and obtain reasonable agreement. Finally, we describe how our model can be applied to achieve the primary objectives of this work (described above) through two examples. The examples demonstrate how a foam hydraulics model can be used to support and guide operational decisions.