bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of Remedial Solution for Removal of Cured Resin Damage
Authors: Belakshe Ravikant , Songire Sumit , Prakash Chetan 
Published: November 2016

Abstract
Curable resins are widely used to mitigate sand production; however, resins are reactive compositions that, under certain conditions, cure prematurely, thus causing impairment for hydrocarbon production. Mechanical methods for damage removal are only effective in wellbores and cannot reach the damage in the formation. This paper investigates the dissolution efficiency of newly developed solvents for damage removal by dissolving the cured resin from pore spaces of the sand grains. The solvents are affordable and environmentally acceptable lactone solvents with boiling points above 200°C.
Resin consolidated sand cubes were soaked in two solvents to measure the ability to dissolve the cured resin at ambient temperature to 100°C. Core flooding tests were performed on resin consolidated sandpacks at 90°C to quantify solvent efficiency for removing damage caused by excessively cured resin. For quantitative analysis, sandpacks were prepared and initial permeability was measured, followed by pumping a resin composition in excess through the sandpacks to create damage by the cured resin. Damage was measured in terms of reduced permeability. Finally, damaged sandpacks were treated with solvent and regained permeability quantified the efficiency of resin dissolution.
Qualitative results showed that the solvents evaluated in this study were able to dissolve and remove cured resin from the sand surfaces effectively. The chemical reaction between cured resin and solvent is temperature dependent, and solvent performance increases with increased temperature. The dissolution mechanism is attributed to the high polarity of solvents, which allows them to react with the polar groups in cured resins. Quantitative analysis showed that the two solvents tested were able to dissolve cured resin in respective sandpacks, and regained permeability was observed from ~26 to ~85%, depending on resin type, when tested at 90°C. These single-component solvents are effective in terms of removing damage imparted by aqueous-based resin (ABR) as well as solvent-based resin (SBR) systems.
The described study is a step toward providing environmentally benign, chemically robust, and thermally stable solutions in view of current requirements by the oil and gas industry. The ability of the solvents to remove the cured resin could be beneficial in terms of eliminating formation damage caused by improper resin treatment. In addition, the same solvents can be used for cleaning equipment, wellbores, and completion tools which have been damaged or plugged by noncured or cured resin.
Intelligent Thinking Enables Emergency Well Killing in Sand Producing Gas Well Using Conventional Resources Huge Time Saving
Authors: Borah J. B. , Rabha N. 
Published: November 2016

Abstract
This paper presents an emergency well killing operation using rig less Coiled tubing unit intervention in a highly erosive environment. Conventional killing operation had resulted in severely eroded and punctured coiled tubing due to sand ingression and subsequent killing failure previously unseen in OIL's areas of operations. This called for reconsideration and alterations to conventional methods using the same available equipment and thereby successful killing of the well.
Sand ingression though common in OIL's oilfields had never previously compromised well completion to such degree. Well no. "DHL" was a gas producer producing 40000-50000 SCUMD of gas. Pressure build-up of 170 ksc was noticed in tubing, 5 ½" casing annulus and also in 9 5/8" casing annulus. Hole-probe survey of the well showed sand and mud build up. Subsequent MIT log survey of the well showed corroded and severely damaged completion. This rendered the well incapable of being killed by conventional methods of killing. Coiled tubing unit was deployed and it was tried to kill the well. However the first attempt failed to subside the well pressure and upon pull out severe pitting of the coiled tubing surface and tubing puncture was encountered due to the sand ingression. Alterations were thereby made in the circulation procedures and successful killing of the well was achieved for remedial work over operations.
Gas well killing is always critical and such conditions of compromised completion, sand ingression and erosion coupled with abnormal pressure build up further adds to the criticality and safety hazards. However with intelligent thinking the job may be achieved with the same resources saving costly man-hour, runtime of machine and downtime of reservoir. Coiled tubing thus proves to be a versatile tool for intervention in wells where regular methods are no longer feasible. In addition to this, with minor tweaks using the same equipment, such critical operations may be carried out as well which might seem unachievable at first.
An Analysis of Multiplicative Schwarz Procedure in Coupling of Reservoir and Networks in Next-Generation Reservoir Simulators
Authors: Temizel Cenk , Putra Dike , Gok Ihsan M. , Zhang Ming , Duangprasert Tanabordee , Aktas Sinem , Tek Suleyman , Balaji Karthik , Ranjith Rahul 
Published: November 2016

AbstractWith the increasing use of reservoir simulation, not only in conventional reservoir modeling, but also in complex and large reservoirs, the need for faster and more robust modeling of reservoirs, along with the facilities and surface networks, has become crucial to meet the requirements of modeling either large or multiple sub-reservoirs with thousands of wells and surface networks, including pipelines and gathering centers, connected all the way to the separators. Next-generation reservoir simulators have begun replacing conventional reservoir simulators over the last decade in conjunction with the addition of more features that enable them to model different phenomena of reservoir fluid flow and recovery techniques, putting them at the forefront of reservoir simulation. While next-generation simulators offer more convenient solutions through surface-subsurface coupling and faster simulations that save time in decision-making processes in reservoir management, there are still some difficulties for the user, as well as in the development of these simulators from a computational point of view. The objective of this study is to outline the strengths and weaknesses along with the challenges in this process to serve as a guide for more efficient use.This study presents an analysis of an important component in the reservoir-network-coupling process in which the reservoir unknowns and network equations are solved iteratively. In the Schwarz procedure, the overlap region consists of reservoir cells included in the network set. An optimum solution for the number of cells extended into the network is important, because as the number of reservoir cells included in the network increases, the cost of the network to solve increases, which can become quite expensive, since bigger and more complex networks are needed to find the solution.This study highlights the effect of using different options for a better understanding of the important components of the coupling process; the results serve as a guide for a more efficient use of this procedure.Reservoir simulation involves several complex calculations to model the full-physics of the subsurface flow, as well as the well and surface facilities. It is not straightforward and easy to model and computationally evaluate the modeled phenomena. Discretizations and approximations contribute to error. Run time is another component that must be managed to find a balance between accuracy, precision, and time. Literature lacks practical examples of the Schwarz procedure, which is another important component in coupling reservoir and surface networks that should be used wisely and efficiently to find a balance between accuracy and computational time. A solid, practical example with the theoretical background that this study outlines will benefit the users of complex and large reservoir simulation models.
Heterogeneous Carbonates: A Modeling Method Ensuring Consistency Between the Saturation Height and Permeability Models for Bimodal Rocks
Authors: Hulea Iulian N. , Dijk Harm , Karnaukh Danila , Spalburg Mirano 
Published: November 2016

Abstract
Due to their heterogeneity, carbonate reservoirs are more difficult to model than their clastic counterparts. The main difficulty stems from the abundance of different pore types in contrast to the typical interparticle pore type encountered in clastics. The multiple pore types make the modelling and prediction of permeability also more difficult for carbonates. Capillary pressures curves or log data are used in order to build saturation height models, also a challenging property with a profound impact and hence constraining it with independent data is desirable.
Recently, we have proposed that permeability and saturation height models have to be consistent, this implies that in the modelling process a new strategy can be adopted. Our work suggests that by using a Brooks-Corey type function, the number of parameters used to predict the 3D hydrocarbon saturation values (for a given porosity/permeability/rock type combination) can be reduced. This approach has also benefits when a saturation height model is prepared for both multimodal and unimodal rocks.
For the bimodal data analyzed, 3 different Rock types are modelled by one Saturation height model per mode, the critical variable distinguishing between Rock types being the microporosity content. By using saturation height models in combination with the conventional permeability measurements, a new approach attempting to extract the fundamental properties of individual pore systems is shown. The key idea is around identifying the governing pore systems from Capillary pressures curves and permeability measurements. The approach results in the ability to predict permeability continuously as a function of pore system mixing ratios.
It will be shown that by decoupling the two pore systems porosities, the permeability heterogeneity can be explained both as a function of porosity and microporosity content.
Free Yourself from Seismic Uncertainties While Drilling with the Deep Directional Resistivity Tool: A Success Story from West African Offshore
Authors: Mahfoud Osama , Chiappero Adrian , Pelissier Nicolas , Merlet Frederic , Dorange Philippe , Majumdar Chandan , Murray Doug , Nono Aaron Nana , Denichou Jean-Michel 
Published: November 2016

Abstract
To meet the increasing energy demand of the world and with the advent of new technologies, operators have been drilling increasingly challenging hydrocarbon pockets to increase recovery of existing assets. New technologies have been developed to achieve a higher degree of accuracy in well positioning and ministering the aspiration supporting the objectives of producing from otherwise impossible targets.
Total E&P Angola, operator in Block-17 in offshore Angola, had launched the CLOV development over four fields: Cravo, Lirio, Orquidea and Violeta, located approximately 140 km from Luanda in water depths ranging from 1050 m to 1400 m. With a focus to develop a highly faulted compartment of the Orquidea field, the ORQ-554 well was planned through a series of faults to achieve the desired drainage length within the unconsolidated channel sands of the Oligocene reservoir. The lack of drilling information for the compartment along with poor seismic resolution of the highly faulted structure owed a high level of uncertainty of ±30 m true vertical depth (TVD) in positioning the well and thus the well could miss the target reservoirs if not calibrated with respect to the structure.
The above challenges, in addition to uncertainty in the reservoir position, orientation, and overall geological structure, were necessitated a technology that could bridge the gap between conventional logging and seismic data. A new directional electromagnetic (EM) logging-while-drilling (LWD) service with a radial depth of investigation on the order of ±30 m has been introduced to allow early detection and mapping of the approaching reservoir with sharper resolution than obtained with seismic measurements and to add important new pieces to the reservoir characterization puzzle. The multilayer inversion coupled with deeper depth of investigation, allowed for the marriage in of seismic and borehole data, leading a more effective and productive wellbore.
This paper will highlight why deep directional resistivity is a step change for doing proactive well placement of highly deviated wellbores as well as for gaining a larger-scale reservoir understanding. Based on the BHA design, the tool was able to provide a resistivity map of the reservoir up to 20m away from the wellbore, detecting multiple layers to improve understanding and in turn support the characterization of the reservoir beyond seismic structural and near-wellbore petrophysical information. In addition, the improved reservoir delineation resulted in more accurate geological models, reserve estimates, and potential improvements to the completion design.
Stratal Slicing: A Tool for Imaging Geologically Time-Equivalent Fluvial Architecture- A Field Case Study
Authors: Lew C. L. , Ismail H. H. , Kadir M. F. A , Tajuddin M. R. 
Published: November 2016

Abstract
The study area covers specific interval with structural and stratigraphic meandering systems within the A Field in Malay Basin. Previosuly, interval-based attributes (waveform classification and RGB Frequency Blending) allow interpreter to visualize composite fluvial features within the interval. However, they do not distinguish the timing and evolution of the fluvial feature within the multi-storey channel bodies. Therefore, stratal slicing technique was then tested in order to solve the issues. The strata within the area of interest in Field A is characterized by anticline and lateral thickness variation, making stratal slicing as the most suitable method for imaging the geological features on the time-equivalent deposition surfaces. Stratal slices were generated proportionally between two interpreted bounding coal surfaces. The stratal slices were then identified and adjusted to their corresponding time-equivalent stratigraphic surfaces based on well stratigraphic markers. Amplitude values from 3D volume were extracted for these slices for imaging and interpreting the fluvial features on the relevant stratigraphic surfaces. Two stacked channel-bodies were mapped using stratal slicing technique, which cannot be visualized from interval-based attributes. The fluvial features observed from the stratal surfaces were then characterized based on 4th order meandering fluvial architecture elements, which consisted of point bar, abandoned channel, crevasse splays, and flood plain. Abandoned channels were analyzed from the channel bodies which are essential in understanding the reservoir compartmentalization, heterogeneity and continuity. The fluvial depositonal maps produced from stratal surfaces served as the control to generate reservoir thickness maps which are crucial in understanding sand distribution for each fluvial feature. In summary, stratal slicing is a pragmatic technique in enhancing interpreter ability to visualize and map fluvial architecture elements at specific time-equivalent stratigraphic surface. The technique helps to identify and characterize the evolution of the fluvial features, resulted in two stacked channel bodies being interpreted. Identifying the abandoned channel which is completely mud-filled helps to explain the reservoir compartmentalization between point bars, which occurred in Field A. This approach is important to guide new strategies of simulation and injection planning for better optimization of the field development and enhanced oil recovery projects.
Application of Innovative High-Temperature High-Density Oil-Based Drilling Fluid Technology in the Efficient Exploration and Development of Ultra-Deep Natural Gas Resources in West China
Authors: Long Li , Xianguang Xu , Jinzhi Zhu , Rongchao Cheng , Jianhua Wang , Shuang Li , Haijun Yang 
Published: November 2016

Abstract
Tarim Basin is the biggest oil and gas bearing basin in China. The ultra-deep formations in the Tian Mountain Front Block in North Border of Tarim Basin is characterized by ultra-high temperature, abnormal high pressure, ultra-thick composite salt-gypsum formation, high-pressured brine layer, and high collapse stress formations are widely distributed, so it will bring great challenge to drilling engineering.
To solve significant non-productive time (NPT) and low rate of penetration (ROP) encountered in dealing with borehole instability, stuck pipe, and high pressured brine influx in the process of drilling operation of the salt-gypsum formations and fractured pay zones, high-temperature high-density oil-based drilling fluid (HDOBM) has been recommended. The high-density drilling fluid system has excellent comprehensive properties, and it could solve the contradiction between safety drilling of ultra-deep wells and formation complexity. Until now HDOBM has been used in the drilling engineering of above 60 wells in this block.
But HDOBM technology is faced with great technical problems to be solved. After many years of technical researches and spread, the existing problems in OBM, including exorbitant price, environmental pollution and high cost caused by downhole losses, have been solved, and a complete set of matching techniques are developed.
HDOBM technology has provided a strong technical support for efficient exploration and development of upper-deep oil and gas resources in Tarim Basin, and it has brought great economic and social benefits.
Solving 16" Deep Harsh Drilling Environment Challenges in South East Kuwait
Authors: Abdullah M. H. , Esmaiel A. H. , Al-Sarraf A. Q. , El Heiny A. H. , Maouche Z. , El–Gayar M. M. 
Published: November 2016

The 16′ Vertical Performance Motor Section is the most challenging section in Exploration Deep Drilling in Burgan Field & All South East Kuwait. The section comprises drilling hard and abrasive Zubair formation followed by reactive Ratawi Shale formation. Several technologies were introduced during the last ten years in search of an economic solution to deliver this section safer and faster with limited success. The objective of this paper is to present the process and technology implemented to drill Zubair and Ratawi Shale formations in two different wells with the same bit at record rates of penetration.Bit durability is generally the main driver in the 16′ section performance. Historically, one to two polycrystalline diamond compact (PDC) bits were utilized in this section and were pulled out for low penetration rates. The new solution required a thorough offset data analysis, including formation porosity, rock strength and abrasiveness analysis, applied drilling parameters and Mechanical Specific Energy (MSE) analysis using software. A customized PDC bit design was then developed using a state of the art bit/formation interaction model combined with an advanced cutter technology and hydraulics pairing for ultimate cutter cooling.The new PDC bit design and the implementation of the softwares used to analyse offset wells drilling parameters and rock mechanics had a significant effect on the bit durability and Rate of Penetration (ROP). The optimized drilling parameters applied as per the former set roadmap aided in managing the bit cutting structure through Zubair and Ratawi Shale formations and the bit was pulled out in re-runnable condition with a new field ROP record. The same bit was then used again in different well and drilled Zubair and Ratawi Shale formations and pulled out with 1, 3 dull condition. Over the two wells drilled, the optimized drilling plan saved National Oil Company over US $200,000, reducing the cost per foot (CPF) drilled by 38% over the field average CPF, increasing the ROP by 55% over the field average and drilling 69% footage more than the previous section benchmark footage.With the engineering evaluation of the offset data and the utilization of the new bit design, National Oil Company managed to drill Zubair and Ratawi Shale section in two different wells with the same bit for the first time and was able to improve drilling efficiency and cutting the drilling cost by eliminating bit trips and cost of new PDC bits.
New Inertial Steering Mode of Point-the-Bit RSS Expands Tool Operational Envelope
Authors: Hussain Sajjad , Li Fei , Rana Vikram , Sharma Varun , Dhaher Karam Sulaiman , Blackburn Jason , Haaland Sigurd , Sivertsen Atle , Eshraghi Daniel , Dashtpour Reza , Lunkad Siddhartha , Hongdul Thanong , Bairwa Girish Kumar 
Published: November 2016

Abstract
The point-the-bit rotary steerable system (RSS) is frequently used for high-profile directional drilling jobs in challenging environments that require high degree of directional control.
To achieve toolface control, the point-the-bit RSS control system requires two inputs: the rotation rate of the collar (CRPM) and the toolface orientation of the bit shaft. Previously, the tool utilized magnetic field measurements to compute the above two parameters and, subsequently, control the toolface for the well trajectory. However, the point-the-bit RSS steerability is compromised in a blind zone (where magnetic field measurement is significantly interfered with, such as inside casing, drilling out of a whipstock window, or close to offset wells, or does not have enough signal strength, such as in a zone of exclusion (ZOE) where the Earth's magnetic field projection on the cross section of tool is low. The new inertial steering mode of the point-the-bit RSS uses accelerometers and a rate gyroscope sensor to steer the tool, and it can be toggled on or off by a mud downlink. This inertial steering mode effectively expands the operational envelope of the point-the-bit RSS by improving tool steering ability when the tool is in a blind zone or ZOE.
Four successful field runs have been completed on one of the largest mature fields in North Sea Continental Shelf (NCS). In the first field run, the new inertial steering mode of the point-the-bit RSS was used to kick off a well, which is close to seven nearby producing wells, from an openhole cement plug through a 37-m narrow window between the 20-in. casing shoe and 13 3/8-in. casing stump and to drill a 17 ½-in. section in the same run. The new inertial steering mode helped to steer in the desired direction with good tool face control in the presence of high magnetic interference. In the second field run, the RSS tool successfully exited the whipstock window and steered in the desired direction using the new inertial steering mode, providing planned separation from the cuttings re-injection (CRI) zone and drilling the 12 ¼-in. section to target depth (TD). In the third field run, the new inertial steering mode was deployed to exit the whipstock window, drill the 8 ½-in. section to TD, and land on top of the reservoir close to five offset wells with a minimum 14-m center–to-center distance. The fourth field run helped the operator to exit whipstock window inside the 13 3/8-in. casing and steer the 12 ¼-in. section underneath motherbore in a high magnetic interference and collision risks environment.
Based on the four successful runs, the new inertial steering mode of the point-the-bit RSS has been proven for its tool face and trajectory control, expanding the tool's operational envelope.