bluuebunny/crossref_metadata_2025_split huggingface dataset:
Brazilian Tensile Strength Test of Orgainc-rich Shale
Authors: Lai B. T. , Li H. , Liu H. H. , Zhang J. L. , Georgi D. 
Published: November 2015

Abstract
Tensile strength is a critical parameter for hydraulic fracturing, predicting crack initiation and propagation in reservoirs, especially in shale reservoirs with complex natural fractures and fissures. The tensile strength of conventional rocks, such as sandstone and limestone, has been well studied and documented. There are many studies of the tensile strength of laminated shale, which focus on scale effects, loading direction, and temperature effects; however, the studies on effects of mineralogy and the water content on tensile strength of organic-rich shales are very limited.
The objectives of this paper are to: 1) Critically review the key parameters that affect the tensile strength of shale; and 2) Experimentally examine the effects of water content, mineralogy and lamination on tensile strength. To do so, a rigorous workflow is followed: 1) Each 1 in. long shale sample is cut into two sub-samples, A and B, of similar length; 2) X-ray computed tomography scan is performed to diagnose pre-existing cracks and defects inside the core plugs; 3) Nuclear magnetic resonance (NMR) is then used to measure the air dry samples’ water content; 5) Sample A is placed on a load frame to measure the tensile strength; 5) Sample B is vacuumed and then saturated; 6) NMR is used to measure the water content after saturation; 7) Tensile strength of the saturated sample B is measured; 8) Samples are crushed, and X-ray diffraction (XRD), scanning electron microsope (SEM) and pyrolysis methods are used to estimate the mineralogy and total organic content (TOC).
A total of 70 Mancos and 48 Eagle Ford shale samples have been tested. The experiment results show that: 1) Bedding plane/lamination has a significant effect on Eagle Ford tensile strength, but no pronounced impact observed for the Mancos shale; 2) The imbibed water significantly reduces the tensile strength by 4.4% to 51.7% as water content increases from 4.45% to 11.7%; 3) Pre-existing detectable micro-fractures can significantly reduce the tensile strength by up to 66%; 4) Eagle Ford exhibits typical brittle hard rock failure configuration, with primary facture and secondary fracture being observed, while for the Mancos shale, only primary fractures are observed; 5) Acoustic velocity test results confirm that Eagle Ford is mechanically transversely isotropic, and Mancos is likely mechanically isotropic.
The First Successful 17½ in. Hybrid Drill Bit Run in Indonesia, Improves ROP and Saves USD 1.9 M in Arafura Sea Deepwater Operation
Authors: Mayendra A. , Pattinama J. , Tokuda N. , Waragai T. 
Published: November 2015

Abstract
A client operating in the deep water of the Arafura Sea faced a problem with drilling interbedded formations in a 17½-in. section. Previously, the section was drilled with a two-bit trip strategy because of various formation types and hardness; a tungsten carbide insert (TCI) bit for Tertiary limestone and interbedded sand, and a polycrystalline diamond compact (PDC) for Wangarlu shale and Puffin sand. Deepwater drilling is a high-cost operation. The new hybrid bit design is a solution to drill the section with one bit run and to save approximately 28 hours of tripping time. In addition, this run improves rate of penetration (ROP), especially in the "hard limestone" above Wangarlu.
The revolutionary PDC and roller-cone hybrid drill bit combines roller cone and fixed-cutter elements. The bit is designed to combine the best attributes of both bit types; the fast aggressive drilling action of the PDC and the smooth, low-torque action of the TCI. Hybrid bits are now being employed in difficult and challenging applications worldwide and are delivering a step change in performance and significantly lowering overall costs.
This paper presents the results of a field test in a deepwater application, and compares the performance of hybrid bits with conventional PDC and roller-cone bits used on offset wells. The interval was drilled in one run, saving USD 1M. Furthermore, the client saved an additional 23 hours, which is equivalent to USD 900,000, by achieving an ROP that is 45% faster than the best offset well.
First Cemented Completion in Egypt
Authors: Luna David , Bezbourah Pearl , Omar Mostafa 
Published: November 2015

Abstract
How can you achieve 20% well costs reductions with no flexibility on wellheads, casings or completion…and two months to do it. Impossible? In Bapetco we said: ″Why not?″ and we took on the challenge.
This paper tells the story of the first cemented completion executed in Egypt. It describes how Bapetco engineered and executed a cemented completion program in 46 days from concept to rig release. Achieving Best In Class performance, successfully cementing 4 ½″ pipe in 6″ hole and generating above 500 Kusd savings; setting new benchmarks for the field and opening up opportunities for the future. All this ensuring Process Safety and compliance with our Well Delivery Processes.
With limited time to develop a well concept, the processes need to be scaled down. To achieve this, an organization needs to ensure high levels of communication and team work.
For Sitra Cemented Completion, the story starts with the idea of cementing the completion to reduce well costs. This concept was endorsed during our Value Creation workshop – which acted as a catalyst. Without it, the decision and endorsement process would have taken months.
It was then up to the well engineers to design a cost effective well to deliver this 4 ½″ cemented completion. It was clear to us: the way to cut costs and remain effective was to drill small and fast.
The biggest limitation to drill a Slim well was the lack of fit for purpose wellhead equipment. So we went out of the box. We re-engineered the conventional well and the casing depths to allow the well to be finished in 6″. It was not the perfect solution, but perfect is the enemy of effective. For this pilot project, the compromised solution would allow us to test the concept and save costs on iron, fluids, bits and time.
None of this can be achieved without all groups deeply engaged, without communication, empowerment and, in some cases, compromises for the greater good.
Two wells have been drilled. Both drilled as Best In Class and both successfully cemented the completion in place. The results are astonishing, 15 days faster than the average of Sitra wells. And we have so much room for improvement, we are following a Technical Limit approach and with fit for purpose wellhead and equipment, the costs savings can grow as high as 1 MMusd per well, which is above 30% of cost reduced.
Enhancing Reservoir Surveillance and Production Sustainability Through Live Digital Slickline
Authors: Said M. Bou , Bilbeisi J. M. , Mansouri T. , Respecia B. S. , Assagaf M. , Cocagne M. , Ambo L. 
Published: November 2015

Abstract
Reservoir Surveillance is made increasingly difficult in mature offshore oilfields that contain a large number of wells with all associated infrastructure. While logging requirements are increasing in order to sustain production from the field and maintain well integrity, the production requirement is increasing and the operational cost has to decrease. These challenges are additional to the existing constraints due to resource limitations in an offshore environment: winch boats for equipment movement, slickline units for downhole safety valve retrieval and tubing checks as well as offshore living accommodation limitations are major factors any of which can cause a halt of rigless logging campaigns.
A new digital slickline unit was used to replace the conventional practice for rigless wireline logging operations in offshore fields (wellhead towers). The old method involved a slickline unit to perform the pre-job and post job work. That's in addition to the logging unit that performs the required production logging job. This process involved a lot of winch boat moves, personnel and shut in days resulting in loss of production between moves. This digital slickline unit combines the capabilities of a slickline unit and a logging unit. The type of slickline it uses allows sending commands to logging tools downhole and receiving data on the surface data acquisition system while logging.
The new approach had multiple operational, financial and HSE&Q impacts. Operationally, performing production logging operations using this digital slickline unit minimized logistics compared to conventional production logging (4 lifting loads Vs. 14 lifting loads). It has also reduced the operation time and trips to and from wellhead towers which resulted in reducing production losses. It also helped achieving the increasing annual logging and slickline KPI's without compromising data QC. Furthermore, HSE&Q was addressed by providing a solution for some integrity concerns related to wells being left with no downhole safety valves between slickline and logging unit movements. Moreover, the probability of incidents caused by improper handling of equipment and tripping/slipping hazards was reduced and most importantly, the option of Medevac by chopper became available in emergency cases due to the reduction in the occupied tower area.
This breakthrough in logging operations from offshore wellhead towers enhanced the operational quality and reduced cost. It represents a part of the continuous efforts to reshape the concept of production and reservoir surveillance (which includes well testing, pressure surveys, etc) by applying new technologies and following new approaches to allow fulfilling larger requirements without making compromises on HSE&Q, production requirement and cost efficiency.
Stimulation Feasibility Study Based on 3D Geomechanical Modelling on Thin and Tight Reservoir with Thin Cap Rock
Authors: Syofyan S. , Sirat M. , Kumar R. , Sumaida S. A. , El Gazar A. L. , Salahahuddin A. A. , Al Shabibi T. A. , Zhang X. , Vantala A. , Chen Y. , Mohamad A. A. 
Published: November 2015

Abstract
The field is located near the UAE capital, Abu Dhabi, with a tight oil and gas bearing carbonate formation. Rapid pressure drop observed, indicates slow charging from reservoir. Typically a tight reservoir like this is developed by hydraulic fracturing. However there is concern of fracture containment and placement. This study was conducted to construct a 3D reservoir geomechanical base model to optimize the completion strategy and production performances for the tight reservoir.
176 laboratory tests/measurements on cores were performed to determine the mechanical properties and petro-physical properties at different intervals in 5 wells over the field. Eight 1D mechanical earth models (MEMs) were constructed to characterize the mechanical properties and stresses along the well trajectories, and the laboratory test results were used to calibrate the mechanical property profiles of the 1D MEMs. A 3D geomechanical model was constructed using seismically-interpreted horizons and faults; mechanical property population and boundary stresses were based on the 1D MEMs. Present-day stresses within the formation and surrounding formations were simulated, and stress evolution from 2011 to 2095 was predicted. Preliminary fracture modelling was performed at two wells to understand feasibility. The major concern is to control fracture containment within the reservoir section, particularly avoiding downward growth. The results indicate that there is tendency of fracture growth downward at one well. However, the downward fracture growth at the other well is not expected. The average upward stress barrier is around 400 psi over the field and the average downward stress barrier is around 800 psi. However, the magnitude varies from location to location. Five completion methods were compared in terms of geomechanics. Acid tunnel and fishbone completion have a very low risk in horizontal well stability. Multilaterals completion has a low risk in horizontal well stability and junction integrity. Acid fracturing and proppant has a relative high risk in fracture placement and containment. It is recommended to perform further completions feasibility study to review the feasible well location, productivity enhancement, economical aspect and operational constraints.
This study reveals that the heterogeneity in the carbonate reservoir has a significant impact on the selection of completion methods. There is a high uncertainty to decide an optimal completion strategy based on 1D geomechanical study results because the large variations in the in-situ stress and mechanical properties. Therefore, a 3D geomecanical study is necessary for the completion selection for heterogeneous carbonate reservoirs, particularly for tight thin plays.
Field Development and Optimization Plan for Compartmentalized Oil Rim Reservoir
Authors: El Gazar Ashraf Lotfy , Alklih Mohamad Yousef , Sumaidaa Saleh A. , Al Shabibi Tariq Ali 
Published: November 2015

Abstract
This work illustrates field development plan and optimization studies conducted on a Middle-Eastern carbonate reservoir. The field lies in an onshore area where increasing urbanization is complicating the field development with regard to safety, accessibility, and drilling sites. The reservoir exhibits relatively fair to poor reservoir characteristics and variable oil water contacts due to faulting, suggesting the presence of 5 different reservoir compartments. A total of 10 wells had penetrated the reservoir out of which 8 wells tested oil and suggested a huge initial gas cap while 2 others penetrated water leg.
Six years of early production scheme (EPS, 4 producers, 1993 to 1998) data in addition to production testing, core (2 wells), MDT (3 wells), PVT (4 wells) data were gathered in order to identify the main uncertainties and test the feasibility of the full field development. EPS indicated production decline coupled with severe increase in GOR and water cut in some wells, after which the producing wells and facilities were P&A due to safety concerns and low productivity.
A number of parameters were addressed and optimized during the full field development plan. These include formation evaluation and modeling parameters based on EPS findings, the limited available data, and pressure support mechanism. Several development scenarios were constructed, consisting of various combinations of horizontal producers and injectors and considering natural depletion, WI, GI, and WAG scenarios targeting the proven reserves. The dynamic modeling suggests that an ultimate recovery of 70% can be achieved by the different injection scenarios. However, considering the complexity of the surrounding environment and the size of the prize, it is recommended that the field development would be economically viable for a period of 10 years under natural depletion, provided the most effective development strategy in terms of number, location, orientation and horizontal reach is adopted.
Application of Micro-Proppant in Liquids-Rich, Unconventional Reservoirs to Improve Well Production: Laboratory Results, Field Results, and Numerical Simulations
Authors: Dahl Jeff , Calvin James , Siddiqui Shameem , Nguyen Philip , Dusterhoft Ron , Holderby Eric , Johnson Bill 
Published: November 2015

Abstract
This paper discusses a study of condensate-rich Barnett Shale stimulation treatments with designs incorporating a micro-proppant (MP). By placing this proppant early during treatment, it can enter into the narrow natural fracture network where proppant even as small as 100 mesh cannot access. A description of the MP, area regional formation and fracture modeling, stimulation designs, reservoir simulation production results, and production comparisons to offsets are presented.
In present day shale plays, maximizing communication between natural fracture systems and the wellbore while also avoiding any damage to those natural fractures are two pillars of optimized stimulation. Increased proppant volume in primary fractures and helping ensure the near-wellbore (NWB) area of these fractures is open are two important stimulation concepts. Further improvements depend on:
Communicating with a greater number of natural fractures. Enhancing the number of secondary fractures opened. Increasing the number of these secondary fractures that remain open for the long term.
Of these three items listed, the third is probably the most challenging. This paper presents a study of MP use with the goal of propping natural fractures in a liquids-rich area of the Barnett, wherein the first and second items listed have already been addressed and provided significant production improvement. A well-to-well comparison of MP use revealed another step-change in an otherwise optimized drilling and completion program. Production history matching using advanced discrete fracture network (DFN) simulations of hydraulic fractures with the complexity of natural fractures included helped provide insight into how relatively small conductivity improvement to the natural fractures significantly improved well productivity. A new complex fracture design simulator successfully predicted the most favorable method within the fracturing design to include a MP entering these narrow natural fractures and thus improving conductivity. With the understanding gained from these new modeling tools, the MP was then field tested and proven to enhance production response.
Challenges of Permanent Downhole Water Cut Measurement in Multilateral Wells
Authors: Arsalan Muhammad , Ahmad Talha J. , Black Micheal J. , Noui-Mehidi Mohamed N. 
Published: November 2015

Abstract
This paper addresses the need and challenges associated with the permanent downhole water cut measurement in multiphase flow at an individual lateral level for efficient and reliable water cut management in a multilateral horizontal well environment. Furthermore, it reviews the available water cut measurement techniques and evaluates their suitability for permanent downhole deployment in multilateral horizontal wells. A comprehensive analysis of the state-of-the-art water cut measurement techniques is presented for the first time in this paper to evaluate their suitability for permanent downhole deployment. Downhole water cut measurement challenges are described in detail and a table is presented comparing various techniques against a set of requirements suitable for permanent downhole water cut measurement.
Effect of Surfactants and Water on Inhibition of Asphaltene Precipitation and Deposition
Authors: Subramanian Deepa , Firoozabadi Abbas 
Published: November 2015

Abstract
Asphaltenes are the most polar component of crude oils and lead to problems such as well-bore and pipeline clogging during extraction and transportation of crude oil. Previous works have successfully used ionic and nonionic surfactants to delay and prevent asphaltene precipitation. It has also been shown that water in pipelines, delays deposition. In this work, the effect of combining water and brine with ionic and nonionic surfactants are investigated in two Middle Eastern crude oils. Results indicate that water and brine do not change the amount of asphaltenes precipitated. The dispersing action of a nonionic surfactant BA, which acts on a colloidal scale to lower aggregate size and truncate asphaltene growth, is not altered by water / brine. The addition of an ionic surfactant, dodecylbenzene sulphonic acid, which molecularly solubilizes the asphaltenes via electrostatic interactions, acts antagonistically when water / brine is present, and destabilizes the crude oil. The above effects are attributed to changes in the electrostatic interactions between the surfactant and the asphaltenes, in the presence of water / brine.
Practical Recommendations for Successful Application of the MPS Facies Modelling Method
Authors: Riou Jeremy , Höcker Christian 
Published: November 2015

Abstract
As part of creating a user-friendly interface for Multiple-Point Statistics functionality in a reservoir modelling package, it has been investigated which strategies and workflows are more likely to satisfy the typical success criteria of oil and gas reservoir modelling purposes. Success criteria would encompass basic requirements such as the ability to honour hard and soft data while creating anisotropic patterns that are more realistic than those of dual-point statistic methods, all with reasonable computation times.
Examples are shown where an MPS recipe, a combination of a training image with certain parameters for training and simulation phases, has given successful results for common depositional settings that have been difficult to model with other techniques. In contrast to common assumptions about training images, it is argued that simplicity may not be a deficiency but a positive feature of a training image as long as generated models satisfy rules of sedimentation and sediment preservation.
Recommendations cover topics such as how to avoid excessive runtimes, how to optimise common parameters and how to handle non-stationary conditions caused by lateral variations in depositional energy or by crossing the interface between facies belts. It is demonstrated that auxiliary variables are a powerful enabler for fast and successful MPS simulations in simple and complex cases. They also facilitate nested, multi-scale simulations by communicating information from larger scale results to subsequent more detailed modelling passes, as is required for extremely complex cases like modelling meander point-bar deposits
A Case Study of the First High-Temperature Unconventional Reservoir to be Drilled and Logged on Land in the UAE
Authors: Hamdy Ibrahim , Shamsi Juma AL , Mahmoud Gehad , Aref Naveed , Reyami Mazin Al , Hosani Mohamed Al , Azzam Samer , Wahsh Mahmoud , Mossallam Kareem , Diab Emad , Lotfy Amr , Madeeh Eslam 
Published: November 2015

Abstract
The future of hydrocarbon production has shifted toward the significant production potential of unconventional reservoirs. As the recovery of oil and gas becomes more complex, drilling through unconventional reservoirs pushes engineering boundaries to new limits to meet world demand in a safe and environmentally acceptable manner.
ADCO decided to drill Well XY-123 in "XY" field in Abu Dhabi. ADCO leveraged extensive experience gained from numerous unconventional reservoir projects throughout the world in addition to the experience obtained from drilling over 1,000 wells in XY field.
The main objective of the well was to acquire as much data as possible to create a database of knowledge for accurate study of the hydrocarbon potential in these reservoirs. Various formation evaluation data (density, neutron, resistivity, gamma ray, and sonic) were acquired from both logging-while-drilling (LWD) and logging using TLC. In addition, formation pressure sampling stations were also extracted from the reservoir. Conventional cores were successfully cut, with a 100% core recovery rate. Full data acquisition across the reservoir was obtained by the ADCO for the first time.
Drilling such wells requires using the latest innovations in drilling engineering principles. These wells are more interrelated and sensitive to small changes than conventional wells. An integrated approach for both planning and execution is crucial because of the potential for risks, including high H2S percentages and drilling across high-pressure high-temperature (HP/HT) reservoirs, and all uncertainties must be properly assessed using solid engineering planning from many disciplines.
This paper describes solutions to numerous challenges in terms of both planning and execution of a high-profile well, in addition to the experience gained. With the shared experience from the lessons learned drilling the well and the offset wells worldwide, this paper proposes a way forward view of the future of drilling unconventional reservoir wells in Abu Dhabi.