bluuebunny/crossref_metadata_2025_split huggingface dataset:
Statistical Approach to Forecasting Gas-Oil Ratios and Solution Gas Production from Shale Volatile Oil Reservoirs
Authors: Makinde Ibukun , Lee W. John 
Published: November 2016

Abstract
The objective of this paper is to present a new method for estimating producing gas-oil ratios and solution gas production from shale volatile oil reservoirs. In order to enhance our knowledge about the production mechanisms of shale oil reservoirs and possibly better exploit their economic potential, it is important for us to be able to forecast production of the secondary phase – gas.
First, we simulated 30 years' production with different reservoir fluids using a commercial compositional reservoir simulator. We then analyzed producing gas-oil ratio data from several representative oil wells using principal components analysis (PCA). With the aid of the Principal Components Methodology (PCM), the principal components obtained from the analyses were used to forecast gas-oil ratios from wells with production histories ranging from 0.5 to 3 years and results were compared to simulated data. We then calculated the cumulative solution gas production from the estimated producing gas-oil ratios.
Stakeholders often focus on oil forecasts for shale oil reservoirs, ignoring the important solution gas produced from these plays. Limited production data, complex flow mechanisms in liquid-rich shale reservoirs, patterns of producing gas-oil ratios and other factors, make the task of forecasting solution gas production difficult. Principal components analysis (PCA) has enabled us to reveal the internal structure of data from the representative wells considered, in a way that best describes the variance in the data. This allowed us to get principal components (data from the PCA calculations) that helped us forecast gas-oil ratios from shale volatile oil reservoirs using the Principal Components Methodology (PCM). We were able to estimate producing gas-oil ratios and solution gas production with reasonable accuracy.
This work presents a unique and novel approach of forecasting production from liquid rich shale plays. It can help to improve reserves estimation, reservoir management and project economics.
Unlocking Reservoir Potential Using an Automated Multi-Stage H2S Treating Technology - First in Onshore, Kuwait
Authors: Mohammed Tawfik M. E. , Al-Matar Bader , Al-Faresi Fahad A. , Qubian Ali , Al-Shati Abbas 
Published: November 2016

Abstract
Produced fluids, from a number of wells completed in a sour reservoir in a giant field in Kuwait contain varying concentrations of H2S, with levels ranging from 1% (10,000 ppm) to 3% (30,000 ppm).
This souring problem made the concerned reservoir undeveloped fully for many years since there are currently no adequate surface facilities and system in place to handle such high amount of H2S.
In order to dynamically mitigate these challenges, a pilot trial of an innovative technology was considered in one of the wells within this field, which has 1.3% (13,000 ppm) H2S concentration. The outcome from this pilot was very encouraging and promising as the H2S level was reduced to the expected set level on a fully automated basis.
This paper highlights the screening process for candidate selection, technical design considerations, KOC-HSE regulations and the successful implementation of this new system on a single well basis and also the lessons learned from the full collaboration between the project team and service provider.
Waterflood Management of a Super Giant Carbonate Mauddud Reservoir, Raudhatain Field, North Kuwait
Authors: Al-Hajeri Nasser , El-Daoushy Ahmed , Safar Ahmad 
Published: November 2016

Abstract
Raudhatain Mauddud is an oil bearing carbonate reservoir in North Kuwait. Mauddud consists of 10 layers with different fluid properties (API from 30 to 14 Deg). Oil production started in year 1957 till year 2000 when started full filed waterflood project. There was quick and clear positive response to water injection in both reservoir pressure and oil production. However there was early water breakthrough in some wells. Many factors have increased challenges in managing Mauddud waterflood project. These challenges were mainly due to reservoir heterogeneity in all layers, structure, injection of low saline water, difficulty to evaluate remaining potential in flooded wells or to identify thief zone before start the injection.
Consequently, the water management strategy has been adapted by implementing methods and tools to tackle these challenges. Interwell tracers have been implemented to study and monitor water movement from the injectors to the producers and evaluate the sealing nature of the faults. Pattern x-section including Tracer, PLT and production data has been used under one page to assist in evaluating and studying water movement within the reservoir. Automated Workflow has been established to calculate VRR for each pattern. Surveillance plan has been implemented including inference tests and PBU/PFO. The injection to production connections and profiles has been modified by isolating top intervals in the injectors and drill horizontal injectors in the bottom of the reservoir. The new horizontal producer has been drilled in the top of the reservoir with advanced completion technology of ICD.
Managing Mauddud Waterflood project in that way has resulted in increase of total Mauddud daily oil rate by 20% with drop in water cut from 40 to 33%.
This paper is summarizing the methods that have been used to manage Raudhatain Mauddud waterflood project as best practices.
Parallel Flaring Challenges
Authors: Al Aydaroos Salma 
Published: November 2016

Abstract
Flare system in the oil and gas industry is an essential requirement for the continuous safe operation of any processing plant. Flares burn off the flammable gases released from the different pressure sources across the plant via a pressure relief valve returning the system back to operate within its safe pressure limits. In cases where the required flare stack or flare knock-out drum required size and height are big, it can be split into two flare systems operating in parallel. This method of flare design is not common.
In one of the fields, parallel flare design is implemented to operate in 2×50% configuration. Each flare system had its dedicated flare knock out drum. Nitrogen purging only is used as a method to prevent air ingress into the flare. The current configuration has the flares operating at the same time whenever there's any relief to the system. The dependency is on the symmetrical piping to distribute the flow equally to the two flare systems. Here, the positive flow towards both flare systems continuously prevents any air to enter. However, the change in the pressure drop across the flare systems during the relief results in the preferential flow of the relief towards one flare system over the other. This preferential flow results in a vacuum effect occurring through the other flare system. The vacuum effect results in air being sucked in from the flare stack causing deflagration to occur and in some cases detonation.
There are different sealing methods for the flare system and the most preferred method is using liquid seal drum downstream of the flare knock out drum. When designing the flare system, one of the parallel flares should be considered the preferred route for relieving with little or no liquid seal in the liquid seal drum and it's called the primary flare. The other one with a liquid seal height corresponding to the maximum emergency relief is called secondary flare and will only operate simultaneously at any point with the primary flare. The purpose of having a liquid seal drum filled with liquid in the secondary flare is to avoid air ingress. In normal scenarios when relief is channelized through the primary flare preferably, it may induce a suction effect drawing air through the secondary flare which may cause deflagration to occur.
This paper will emphasize challenges of designing flare systems in parallel configuration and the different aspects and considerations of such design.
LWD Sonic Through Casing to Measure Slowness and Evaluate Cement Success While Drilling - A First in Saudi Arabia
Authors: Al-Fawwaz A. , Al-Harbi Z. , Al-Ajmi F. A. , Stolte C. , Razwan K. , Ghosh K. 
Published: November 2016

Abstract
Acoustic measurements are used throughout the lifetime of a well, from seismic to production. Logging While Drilling (LWD) sonic is traditionally used to log formation slowness in the open hole. In this case study we show that both, measuring formation slowness and evaluating the success of a cementing operation can be obtained with the latest generation of LWD sonic tools while drilling, thus saving rig time, simplifying operations, and adding safety to well integrity solutions. Both, formation slowness and well integrity are often an essential criterion for the decision whether to drill ahead or to take additional measures to assure well integrity.
In this case study we have demonstrated that there is additional approach wherein formation slowness can also be recorded/captured in cased hole with LWD tools when the cement bonding is sufficient to allow good coupling. Continuous formation compressional and shear slowness was recorded and extracted for most of the interval below Top of Cement (TOC) and some short intervals above TOC. This advanced technique of logging formation slowness through casing with LWD can complement or even save an additional logging run in some cases and therefore result in significant savings to the operator.
Where azimuthal cement evaluation is not a strict requirement, knowing the top-of-cement (TOC) from LWD can help to confirm well integrity without adding rig-time. Should the measured TOC be lower than required, then more advanced analysis can be run for additional investigation.
An Analyzing Model of Stress-Related Wellbore Strengthening Techniques
Authors: AlBahrani Hussain I. , Noynaert Samuel F. 
Published: November 2016

Abstract
The relatively new concept of wellbore strengthening was introduced to tackle the issues of lost circulation and narrow drilling window complications. Wellbore strengthening is intended to increase the effective formation strength and its resistance to drilling-induced fracture formation. The ultimate goal of this concept is reduce trouble time associa and in many cases, allow drilling to continue past zones that would have required casing to be set in order to proceed. Numerous techniques that vary in their effectiveness and applicability were created. Therefore, there is a clear need for a tool that will help cast a critical eye on the use of these techniques.
The model described in this work aims to provide a practical tool that evaluates and predicts the performance of wellbore strengthening techniques in practical situations. The wellbore strengthening techniques covered by the model use stress changes around the wellbore as the primary criteria for enhancing the fracture pressure and effectively enlarging the drilling window. The model relies on geometric principles, basic rock mechanics data, linear elasticity plane stress theory, drilling fluid data, and geological data. It also provides a process for the proper selection of candidates for wellbore strengthening. To achieve that goal, the model creates all of the possible scenarios in terms of well placement, surface location, and trajectory based on input data to define the scenario that will yield maximum results using a specific wellbore strengthening technique.
The results produced by the model are based on a specific case study. They show practical advantages of applying the model in the well planning phase. The analysis performed using the model demonstrates the applicability of a certain wellbore strengthening technique, the effectiveness of the technique, and the best parameters for the technique. Therefore, the analysis shows not only the best case scenario for applying a wellbore strengthening technique, but it also illustrates the cases where applying the technique should be avoided due to a predicted detrimental effect.
A key finding from the model results is the effect of the direction of drilling on the performance of the highlighted strengthening techniques. It is shown that implementing certain strengthening techniques can cause the paths of the largest drilling window and the narrowest drilling window to switch directions.
Implementation of Transformers On-line Condition Monitoring Systems
Authors: Matar Ghada , Mansour Khalil , Nagpal Sanjay , Alasadi Bashar 
Published: November 2016

Abstract
Transformers are critical to electrical power systems and grids. Their reliability and availability is the key to profitable power generation and transmission. Therefore, the continuous online evaluation of transformer dielectric condition, operation and performance is essential and especially after the new development of sensor and computer technology.
Online monitoring system is also found to reduce maintenance cost, extend life time of the transformer, enhance overload capability, detect faults, and avoid unexpected transformer failures and gird blackout.
The purpose of this paper is to introduce the most recent online condition monitoring systems available in the market and applicable for oil and gas industry.
Engineered Encasement Solution for Cooling Water Line Rehabilitation without Plant Interruption
Authors: Bandopadhyay Surya 
Published: November 2016

Abstract
In the Abu Dhabi Gas Liquefaction Company (ADGAS) owned Liquefied Natural Gas plant in Das Island, Abu Dhabi, the cooling water pipe network consists of cement-lined carbon steel pipes.
The existing underground cooling water (UGCW) networks have been in operation since the commissioning of Das Island LNG Plant almost 37 years ago. The cooling water running through the pipes is untreated sea water.
The pipes are of material grade API 5L Gr B / ASTM A106 Gr B with cement lining thickness of 11mm for pipes above 24" diameter, 10mm for pipes between 24" and 18" diameters and 8mm between 18" and 12" diameters and is routed underground at up to 3-4m depth from the pavement level. On the outer side of the pipes there is protective wrapping of PVC bitumen backed tape.
Hybrid Stochastic Algorithms: A Novel Application in Modeling Facies Cycles and Properties of Carbonate Platform, Onshore Abu Dhabi
Authors: Salahuddin Andi A. , Seiari Jamila M. , Hammadi Khaled E. 
Published: November 2016

Abstract
The carbonate reservoirs lithofacies discussed in this paper contain heterogeneous pore types and properties. The challenge in predicting the distribution of the pores properties is through the technique used to construct a representative model to effectively describe the lithofacies distribution in 3D.
The studied reservoirs are part of the Lekhwair and Kharaib Formations that were deposited in carbonate platform environment varied from lagoon, shoal, to ramp settings during Valanginian-Barremian age. Core and well-log data from an onshore oil field of Abu Dhabi were used to establish lithofacies distribution schemes and high resolution sequence stratigraphy (HRSS) frameworks. Twenty four lithofacies were identified based on faunal content, texture, sedimentary structures, and lithologic composition. HRSS interpretation indicated twenty one fourth-order parasequences that displayed aggradational, progradational, and retrogradational stacking cycles.
A novel stochastic multirealizations modeling of lithofacies and their property distribution has been developed to characterize the subsurface complexity. The method combined depositional environment, HRSS, and diagenesis trend, and then integrated them with dynamic data to generate a holistic reservoirs characterization and representative simulation model.
The workflow is as follows: Detailed core, thin section and lithofacies description;Paleoenvironmental interpretation;HRSS interpretation;Field scale stochastic modeling;Flow simulation and history match validation.
Field wide reservoirs lithofacies and property distributions were modeled and constrained by the identified HRSS framework. Hybrid combination of Truncated Gaussian Simulation (TGS) and Sequential Indicator Simulation (SIS) algorithms were used. This allows generating equiprobable multirealizations of realistic lithofacies cycles and properties trend in the area. The use of lithofacies distribution provided flexibility in the modeling workflow as it offers the outline for rock properties distribution such as rock types, porosity, permeability, and water saturation. The resulting multirealizations demonstrated consistency with the conceptual scheme, outcrop analogs, and geostatistical trend.
This innovative approach has recently been implemented successfully in the studied field reservoirs. The resulting dynamic model depicted a good production history match; hence it will provide reliable production forecast and reservoirs development plan.
Apparent Shear Yield Stress of Filter Cakes Determine Flow Initiation Pressures and Near Wellbore Return Permeabilities
Authors: Suri Ajay , Sharma Mukul 
Published: November 2016

Abstract
Laboratory testing of drilling/drill-in/completion fluids for evaluating formation damage potential requires return permeability tests. It is shown that the apparent shear yield stress of the filter cakes developed by these fluids at the wellbore interface determines the flow initation pressure and the near wellbore return permeabilities during onset of production.
Traditional bentonite clay based and recent non-damaging sized calcium carbonate polymer fluids were chosen to represent the wide variety of water-based drilling and completion fluids used in the field. A standard API filter cell was used with an over-balance of 100 psi and a filtration time of 16 hours for preparing the filter cakes. A constant strain rheometer was used to measure the filter cakes' apparent shear yield stresses. Linear strain and dynamic strain sweep tests were successfully conducted to get the estimates of the apparent shear yield stress of the prepared filter cakes.
Filter cakes prepared with bentonite muds showed an apparent shear yield stress of 800 Pascals (0.12 psi) while filter cakes of typical sized calcium carbonate drill-in fluids showed smaller apparent shear yield stress values between 250 and 450 Pascals (0.06 psi) varying with the median diameter of the calcium carbonate particles. The higher apparent shear yield stress of bentonite filter cakes was attributed to the smaller size of bentonite clay particles (&lt; 2 microns) compared to the drill-in fluid sized calcium carbonate particles (&gt; 2 microns). Two models were developed that used the apparent shear yield stress of these filter cakes and predicted the flow initiation pressures (FIP) and the return permeabilities. The models matched reasonably well with the experimentally measured FIP and return permeability ratios.
A novel approach for measuring and utilizing the apparent shear yield stress of filter cakes is presented that predicts FIP's and return permeability ratios during the onset of production. A new protocol is suggested that measures the filter cakes' apparent shear yield stresses to model the FIP and the return permeabilites for a given drilling and completion fluid.
Challenges and Countermeasures of Directional Drilling Through Abnormal High Pressure Salt/Anhydrite/Calystone Layer in HFY Oilfield of Iraq, A Case Study
Authors: Nie Zhen , Luo Huihong , Zhang Zhenyou , Chen Yufeng 
Published: November 2016

Abstract
The Lower Fars formation located at the depths of 1350-1950meters, it mainly consists of alterations of claystone, anhydrite and salt layer with a 2.22 g/cm3high pressure aquifer in 1400~1600m, the safe drilling window is limited to 0.15g/cm3,the 10~15m interval under this formation is the main Jeribe-Kirkuk reservoir in this oilfield. More than 100 clusters of directional and horizontal Jeribe-Kirkuk wells will be drilled. The high risk of wellbore instability in Lower Fars has resulted in wellhole collapse, overpull, pipe sticking, and sticking during running casing and the high-density salt-saturated drilling fluid is easily deteriorated and loss of liquidity while directional drilling through the Lower Fars interval. In the 1st directional well JKD007, stuck pipe was encountered 3 times and drilling sidetrack holes were required 2 times. In the 1sthorizontal well JK060H,a stuck casing resulted in setting the casing shoe in shallower depth. This study has been carried out in order to decrease the risk of sticking and ensure drilling a smooth, directional hole in the Lower Fars formation. So the lithologic creepage rules and the hole deformation rules in the Lower Fars, major causes for pipe sticking, a safe window of drilling fluid, critical the density of drilling fluid under the different inclinations and technology countermeasures were determined through build the wellbore stability analysis models based on the results of rock mechanics tests of the salt, anhydrite and claystone, the pore pressure, in-situ stress and rock deformation and failure law. The critical density of drilling fluid increase to 2.35 g/cm3 is proposed while the inclination about 35°in Lower Fars formation in order to reduce the risk of pipe sticking; the more stable well trajectory is recommended baesd on the lower Fars deformation rules through adjusting the location of KOP to reduce the inclination and directional length in Lower Fars and considering the distribution of the salt/anhydrite/claystone, and a new kind of the high-density saturated salt-water mud was developed through introducing a kind of new polyamine type inhibitors, synthetic polymer thinner and optimizing the composition and dosage of weighting materials. Since then,11 directional wells and 2 horizontal wells have been drilled and completed with great success for the Jeribe-Kirkuk wells. Average directional drilling time in Lower Fars is reduced from 74days to 59days and the average ROP has improved by 9.64% using a 2.35g/cm3drilling fluid with a controlled viscosity of less than 120s. This paper will systematically describe the details of the sticking mechanism, the Lower Fars wellbore stability analysis method, and the effectiveness of the countermeasures used in directional drilling through the high-pressure salt/anhydrite/claystone layer.
An Integrated Geomechanics and Real Time Pore Pressure Approach helps to Successfully Drill the First Horizontal Well Along the Minimum Horizontal Stress Direction in Tight Sandstone Formations
Authors: Vasquez Vladimir , Roux Stephane Le , Heylen Julien , Eissa Hassan , Almazaqei Akram 
Published: November 2016

Abstract
An operator in the Middle East is seeking to develop its natural gas resources to meet rising energy demand. This operator is drilling horizontal wells along the minimum horizontal stress direction in an attempt to generate multiple transverse fractures during stimulation to increase gas production in unconventional reservoirs. However, drilling operations in these wells is extremely difficult because of the in situ stress environment; these conditions result in a significantly increased number of stuck pipe incidents, wellbore collapse, incurring remarkably high nonproductive time. This paper describes the methodology used to define and calibrate the safe mud window for the curve and lateral section of the first horizontal well drilled in tight sandstone formation by conducting a wellbore stability study and real time drilling geomechanics and pore pressure monitoring. The wellbore stability study incorporates all logs and rock mechanical properties propagated on the direction survey and proposed formation tops of the planned horizontal well X-56. The well was drilled successfully with a mud weight of95 pcfto 98 pcf in the curve section and 100 pcfto 106 pcf in the horizontal section. Major technical contributions of this paper include: (1) Characterization of geopressures and stress field in different formations calibrated with real time data, (2) back analysis methodology to estimate fracture gradient from formation integrity test (FIT) & image logs, in addition to this (3) pore pressure zones designation along the stratigraphic column.