bluuebunny/crossref_metadata_2025_split huggingface dataset:
Normal Stress Rheology of Drilling Fluids and Potential in Lost Circulation Control
Authors: Kulkarni Sandeep D. , Savari Sharath , Maghrabi Shadaab , Jamison Dale E. , Kumar Arunesh 
Published: April 2013

Abstract
Investigating lost circulation in DEA 13 JIP has shown that it is difficult to arrest losses while drilling with non-aqueous drilling fluids (NAF) as compared to aqueous drilling fluids (AF). In an earlier work (Kulkarni 2012), a novel method was discussed to characterize the plugging (of LCM particles and Fibers) performance of non-aqueous and aqueous drilling fluids using viscoelastic parameters under shear stress (First Normal Stress Difference=N1). This paper discusses the modification of drilling fluids (particularly non-aqueous fluids) to combat lost circulation. N1 measured at low and moderate shear stresses for different aqueous and non-aqueous drilling fluids shows that the magnitude of N1 for AF was significantly higher than that for NAF; although, the FANN® 35 viscometer shear rheology of both was similar. Another important finding was that adding certain polar-organic compounds to the NAF improves its N1 magnitude remarkably, which in turn was found to improve the drilling fluid's performance in lost circulation applications. For representative AF and NAFs, with the same FANN 35 viscometer rheology properties and lost circulation materials, fracture plugging efficiency was probed on a Permeability Plugging Apparatus (PPA) using a tapered slot. The plugging performance of the LCM in the AF was significantly better than in the NAF for the same combination of LCM. This difference in plugging performance was attributed to the noticeable difference in N1 observed for these two drilling fluids. The relation between N1 and plugging efficiency became evident when the addition of polar-organic compounds to the NAF increased its N1 and improved its plugging efficiency. These findings could be used to tailor the NAF for LCM treatment during the mud design phase and help alleviate trial-and-error in the LCM design.
Gas Formation Testing in Exploration Phase
Authors: Hassan Rozlin , Haddad Sammy , Wa Wee Wei , Johan Zailily , Lim Lee Chin 
Published: April 2013

AbstractReservoir rock properties, fluids' type and pressure are fundamental parameters for the successful reservoir management in field development planning. Key reservoir parameters are namely horizontal permeability, vertical permeability, damage skin, radius of investigation and reservoir pressure. Together with the reservoir fluid properties, they form critical input to comprehensive production and reservoir engineering studies.Exploration work done through a 3 wells campaign in three main gas fields offshore Malaysia is presented in this paper. The main objective for the operator is to acquire an early and quick identification of hydrocarbon prospects for appraisal wells' planning. Compared to the conventional full scale DST, the combination of Downhole fluid analysis and interval pressure transient test (IPTT) by wireline formation tester were deployed to achieve these objectives.This paper illustrates the successful downhole reservoir fluid identification and formation testing in the reservoirs with the mobility range of 365 to 3020 md/cP. At the interval of interests with the presence of hydrocarbon, dual packer formation tester module offers selectively straddling reservoir sections to provide the capability to conduct controlled local production and interference for reservoir parameters estimation. The methodology, applications and suggested best practices applied throughout the campaign are presented in this paper.
Sand Management Methodologies for Sustained Facilities Operations
Authors: Rawlins C. Hank 
Published: April 2013

Abstract
Facilities sand management is tasked with the goal of ensuring sustained hydrocarbon production when particulate solids (i.e. sand or proppant) are present in well fluids, while minimizing the impact of these produced solids on surface equipment. Particle size and total concentration of formation sand or proppant determines their net effect on production and the resulting operability of surface facilities. Conventional sand management control focuses on sand exclusion from the wellbore, either by production limits or completion design. Completions may adversely affect inflow due to skin buildup and both controls impede maximum hydrocarbon production. Alternatively, co-production of fluids and solids, with subsequent sand handling at surface facilities, is an inclusion paradigm that allows sustained hydrocarbon production. Produced solids are removed at the wellhead upstream of the choke using fit-for-purpose equipment. This methodology allows for increased or recovered hydrocarbon production, while their removal upstream of the choke protects facilities operations.
A description of the design, performance, operation, and effect on production rate is provided for sand inclusive production through application examples in the Caspian Sea, Indonesia, and South China Sea. Specific reference is given towards wellhead desanding, which forms the greater part of this approach, and has expanded from the first field installation in 1995 in the UK to every major oilfield producing region. Implementation of dedicated facilities sand management technology has resulted in increased hydrocarbon production from sand producing wells, extension of well life on marginal fields, and re-start of shut in wells.
Formation Silicate Scale Inhibition during Alkaline Flooding: Static Model
Authors: Basbar Ashraf E. , Elraies Khaled A. , Osgouei Reza E. 
Published: April 2013

Abstract
Scanning electron microscopy (SEM), X-RAY diffraction (XRD) and X-RAY Fluorescence (XRF) were employed to investigate the silicate scale during alkaline flooding. The formation of silicate scale is a multi-step process, involving silica dissolution, silica polymerization, and precipitation with other ions. It is a massive headache burdened to the oil and gas industry today. The aim of this study is to come out with a static model based on series of experiments to investigate the silicate dissolution ratio using quartz sand core samples. Synthetic brine with different salinities ranged from 5,000 ppm to 60,000 ppm and different alkali concentrations ranged from 0.4% to 1.2% were utilized to determine the change in soluble silica concentrations. In addition, two inhibitors; namely, Boric acid (BA) and Ploy Acrylic Acid (PAA) were screened and the optimum concentration for each inhibitor was identified. Based on the results from this experimental work, the silica dissolution ratio increased significantly with the increase in the the alkali concentration. The silica dissolution ratio increased from 1.1% at 0.4% alkali concentration to 4.6% with alkali concentration of 1.2 %. By introducing BA and PAA as inhibitors separately, significant improvement was observed in both cases. Using 50 mg/l of BA and PAA, 3.1% and 11.2% of the dissolved silica was inhibited, respectively. However, only 37.2% was inhibited when the BA concentration was increased to 350 mg/l, while 72% of the dissolved silica was inhibited when 350mg/l of PAA was utilized. The outcome from this research indicates that the best inhibitor does not prevent the silicate scale, but it might reduce it. This study may assist in understanding the mechanism of silica dissolution process and its effect against alkaline flooding.
Improving Production Using a Unique Self-Positioning Tool to Deliver Four Types of Acid Stimulations in a Well: Matrix Penetration, Acid Washing, Many Micro/Mini Fractures, and Large Fractures
Authors: Surjaatmadja Jim B. , AL Hamad Abdullah M. , Waheed Arshad 
Published: April 2013

AbstractThe use of coiled tubing (CT) to distribute acid for stimulation has shown good results in the past. Use of CT allows the acid to be delivered evenly throughout the well. This is especially true for openhole wells in which bullheading acid into it will only acidize the heel of the well. While often used, such approaches will create massive enlargements at the entry point where the acid first contacts the acid soluble rock, causing ineffective treatments and re-entry issues. Wellbore collapse often follows. The use of CT as a pinpoint delivery method is therefore preferred.An even better approach with CT is to add a jetting tool to the bottomhole assembly (BHA). With this configuration, it is an option for different treatments that can be completed in a single trip, such as simple matrix acidizing, acid wash, or even hydrajet assisted acid fracturing (HJAAF). This latter one can be used to place many microfractures or minifractures in the well; and by increasing the bottomhole pressure with annular injection, the HJAAF can create medium to very large fractures for sustained productivity.This paper discusses the implementation of this combined process in the Middle East. The wells in the discussions have large openhole sections to be stimulated. Moreover, as often found in the brownfields, a small production tubing that has been weakened by corrosion and erosion is present and cannot be removed for many reasons, such as losing the well and related costs. The CT and associated tools in such cases must therefore be very small to enter through this tubing and its associated "no-go" restrictions. A small OD unique jetting mechanism that places the jet nozzles closer to the wellbore wall was therefore necessary to perform this task. Excellent results were obtained using this process and are presented in this paper.
High Resolution Seismic Imaging and Fault Detection using Walkabove and Rig VSPs in Ras Budran and Ras Fanar Fields in The Gulf of Suez
Authors: El-Hateel Mohamed S. , Ahmad Parvez , Ismail Ahmed H. , Ashraf Ahmed , El-Fadeel Mohamed A. 
Published: April 2013

Abstract
The Gulf of Suez is well known for complex geological setting due to salt plays, complex faulting, high dips etc. Surface seismic is typically affected by strong multiple activity and heavy energy losses resulting in low resolution seismic, making the seismic imaging a big challenge for Geophysicists. Consequently, the geophysicists face problems while planning and drilling new development wells due to unexpected events i.e. faults, missing targets etc. Suez Oil Company conducted standard rigside borehole seismic surveys to address some of the seismic issues in their concessions. Such surveys also resulted in uncertainties in time-depth relation and poor imaging even in wells with low inclination.
The paper presents case studies where VSP surveys were conducted in Zero Offset geometry in vertical and Walkabove in low and highly deviated well sections in Ras Budran and Ras Fanar offshore fields. VSP programs were designed after pre-survey modeling simulating different scenarios to meet the objectives as well as ensuring safety and cost effectiveness. Accurate time-depth relations were derived in wells with low as well as high inclination. Three-component full waveform data were processed leading to high resolution 2D images beneath the deviated well trajectories. The results helped in reducing surface seismic uncertainties for shallow as well as deep targets, and refining interpretation. Additionally, VSP image helped to control the structural boundary as new faults were delineated successfully, which were not detected in low resolution 3D surface seismic.
Non-intrusive Corrosion Erosion Monitoring For Subsea Applications
Authors: Instanes G.. , Kristiansen S. H. , Pedersen A. O. 
Published: April 2013

Abstract
The oil and gas industry has a need for reliable monitoring of changes in wall thickness both topside and subsea. It is important to detect and monitor the effect of corrosion and erosion as this may reduce the life-cycle cost and increase the lifetime of industrial infrastructure, ships, aircrafts, ground vehicles, pipelines, oil installations, etc. Even topside the conditions of operation can be extremely hostile, facing problems like surface roughness, fluid loading issues, temperature variations, and a host of other factors that make development of a robust wall thickness assessment tool a challenging task. Deploying a monitoring system subsea makes the application even more demanding when you have to take into account factors like high pressure and limited access. Over the last years ClampOn have offered a topside corrosion-erosion monitor (CEM) for monitoring changes in the wall thickness of such infrastructure. Major advantages of this technology have been its non-invasiveness, high repeatability, high coverage and the lack of any transducer movement, also making it an excellent candidate for subsea use. The measurement principle is based on dispersion of ultrasonic guided wave modes, and by using electromagnetism these waves can be transmitted through the pipe wall without the sensor being in direct contact with the metallic surface. It is installed on the outer pipe wall to produce real-time wall thickness information – not as a spot measurement, but as a unique average path-wall thickness. With several successful installations topside, the technology has now also been made available for subsea installation.
Dual ESP as a Solution for Cross-flow Challenges. Case Study, Well A-06, Muglad Basin, Sudan
Authors: Fadl Abdalla Tajeldin , Ahmed Ahmed Elrufai , Osman Younis Mohd , Abdelrahman Hatim Muhallab 
Published: April 2013

AbstractField H has several wells producing commingled with different pressure regimes. PLT runs have been carried to assess the layer-wise pressure and fluid contribution. The results revealed the problem of cross-flow in shut-in condition between the two producing reservoirs in well A-06 among other wells. The PLT also confirmed there is no contribution from lower pressure zone alongside the high pressure zone even in the highest drawdown. In such case commingled production by single ESP will not be optimized and alternatively, one zone must be isolated and production from that layer is sacrificed. This situation mandates quest for a solution that offer total separation of production from each layer. In search for a solution to the problem the Dual ESP application was explored. Dual ESP technology can be used to separate production from two zones of the well where commingled production is not possible. Several Dual ESP configurations were explored and opt for the concentric configuration. Installation of Dual ESP in well A-06 provided solution to enhance oil production from multiple layers where commingled production is not possible. This paper discusses the application of Dual ESP in well A-06 as a case study and shows the valuable results achieved and the way forward.
Optimization Of Horizontal Well Length: A Case Study In The Fractured Basement Reservoir Of The South-east Dragon Oil Field In Viet Nam.
Authors: Lu Vi Dinh , Nguyen Quy Minh , Mai Lan Cao , Tran Dao Xuan 
Published: April 2013

Abstract
After several discoveries of oil and gas in fractured basement reservoir such as White Tiger, Dragon, Aurora and Ruby in 1990s, the basement on the continental shelf of Vietnam has become a major target for domestic and foreign oil companies. Oil produced from basement is accounted for more than 90% of the total produced oil. Due to lesser and lesser new discoveries and most of the big oil fields are in declining phase, the Improved Oil Recovery (IOR) methods are bringing advanced technological solutions to boost oil recovery from mature fields, geologically complex low permeable and fractured reservoirs in the future. Among the IOR techniques, horizontal wells appeared to be a promising one in both short and long term of reservoir life.
Horizontal well (HW) has a higher productivity and pay contact as increase the length of well, thereby reducing the number of wells required to drain the reservoir. In the case study presented, the efficiency of horizontal well will be evaluated by analyzing horizontal well performance. Both analytical and numerical solutions will be investigated. A 3D numerical model of the South-East Dragon field was set up with five production wells and one injection well that is known as a base case. Then running base case is to find the appropriate places for putting new well. Ten interesting scenarios are presented in this paper where the horizontal well is analysised both HW location sensitivities and HW length sensitivities. In addition, this research described a step-by-step procedure that can be used when performing an economic analysis of a horizontal well project. The results from the case study indicate that a combination of factors including total economic, analytical and numerical simulation is required to optimum horizontal well length in the fractured basement reservoir of South-East Dragon oil field in Viet Nam.
Hydraulic Unit Estimation From Predicted Permeability and Porosity Using Artificial Intelligence Techniques
Authors: Shujath Ali Syed , Hossain M. Enamul , Hassan Md. Rafiul , Abdulraheem Abdulazeez 
Published: April 2013

Abstract
Rock classification or assigning a type or class to a specific rock sample based on petrophysical characteristics is a fundamental technique to reduce the uncertainty in prediction of reservoir properties due to heterogeneity. One of the popular approaches is to classify a reservoir rock from the fundamentals of geology and the physics of flow at pore network scale. In this approach, rocks of similar fluid conductivity are identified and grouped into classes. Each grouping is referred to as a hydraulic flow unit (HU). HUs are estimated for the uncored section of the wells from wire line log data received from field using three popular artificial intelligence (AI) techniques such as (i) Adaptive Network Fuzzy Inference Systems (ANFIS); (ii) Functional Networks; and (iii) Support Vector Machines. HUs can either be predicted directly from wire line log data as a classification model or can be estimated indirectly from predicted permeability and porosity. In the present study, HUs were predicted employing both approaches. The comparison of the two approaches shows that it is a better practice to estimate HUs by directly relating them to well logs. Calculation of HUs from predicted permeability and porosity results in inferior accuracy. This is due to the accumulation of errors during the estimation of permeability and porosity. The Knowledge of HUs acquired from well logs can significantly help in determining ultimate hydrocarbon recovery, optimal well placement, and well stimulation. Thus, the finding of this research will impact the economy of the development and operations of a field.
Enhancing Oil Recovery through High Level Data Mining Technology
Authors: Adeyemi B. J. , Ajilo V. I. , Falode O. A. , Falobi E. O. 
Published: April 2013

Abstract
The world's energy consumption has risen geometrically over the last three decades due to advancement in technology. In response to this ever increasing rising demand, other sources of energy have been explored. Reports show that fossil fuels (crude oil and natural gas) continue to take the lead despite these efforts. Hence, the Oil and Gas industry has put in a lot of technical measures to meet up with this high energy demand. Many works have been done on how to increase reserves and ultimately increase recovery but little has been achieved in this area. Therefore, a more reliable, efficient and effective way of enhancing recovery is necessary to make headway in countering this challenge. This research seeks to provide the feasibility of enhanced oil recovery (EOR) projects using high level data mining technology in the African Oil Producing Regions.
Data mining is a process which finds useful patterns from large amount of data. Data analysis process involves data exploration, pattern identification and pattern deployment to make accurate judgement necessary for EOR investment decisions. It provides a significant reduction in the level of uncertainty when compared with other existing techniques. In our concept, artificial intelligence and genetic algorithm was employed and recommendation made.
Results show that data mining technique is a robust tool for making EOR investment decisions, right from the early life of a field. Thus, this concept makes it more economical to execute EOR projects with lower level of uncertainties. Marginal fields can also be invested upon using data mining techniques.
Polymer-Locked, Crush-Free Wireline composite Cables Reduce Tool Sticking and HSE Risk in Emerging Deepwater Reservoirs
Authors: Sarian Serko , Varkey Joseph , Protasov Vadim , Turner Jennifer 
Published: April 2013

Abstract
The recent breakthrough developments of polymer-filled armor cables with crush-free electrical cores, effectively eliminate inherent limitations of wireline logging cables. These novel cables deployed with a complete high-tension conveyance package have effectively reduced deepwater-wireline tool sticking occurrences and the subsequent lengthy fishing operations in emerging Deepwater and depleting reservoirs.
Unique composite polymer technology locks the normally unbound cable armors to the core. Further Coldflow and crush resistant protection is added to the cable core itself. The result is a mechanically rigid, torque-balanced and crush-free wireline cable that effectively eliminates known issues with core codlflow, cable rotation & plastic stretch, armor stranding & bird-caging, while enabling high-tension spooling on a drum without the use of tension relief system (Capstan). With spooling tensions up to 13,000 lbf, instantaneous pulls of 18,000 lbf and a safety margin of 9,000 lbf, the complete high tension package offers tool sticking mitigation capabilities only possible previously with a Capstan package. Additional benefits include but not limited to fully seasoned new cable and reduced frequency of cable maintenance. Furthermore, the elimination of the dual drum Capstan eliminates significant operational risk.
TuffLINE 18000 - a composite cable was deployed successfully without Capstan in Deepwater Australia for an operation including formation pressure and sampling in a reservoir with a high tool sticking potential. In a particularly challenging situation in the Mediterranean where Capstan could not be deployed, TuffLINE 18000 was used in 5 descents resulting in 96 hrs of rig time savings while reducing HSE and operational risk.
With the proven financial and HSE benefits, polymer filled composite wreline cables and the high-tension conveyance package reduce wireline tool sticking risk.