bluuebunny/crossref_metadata_2025_split huggingface dataset:
Incorporating Lithofacies Classification and well logs into Statistical Learning Algorithms for Comparative Multisource Permeability Modelling
Authors: Al-Mudhafar Watheq J. , Mohamed Lamees 
Published: September 2015

AbstractMultisource and multiscale modelling of formation permeability is a crucial step in overall reservoir characterization. Thus it is important to find out an efficient algorithm to accurately model permeability given well logs data. In this paper, an integrated procedure was adopted for modelling formation core permeability given well logs and Lithofacies classification for a well in sandstone formation in South Rumaila Oil Field, located in Iraq. The core permeability was modelled give well logs interpretation: neutron porosity, shale volume, and water saturation as function of depth, in addition to the vertical Lithofacies sequences. The statistical learning algorithms that were adopted in this paper are Generalized Linear Models (GLM) & Smooth Generalized Additive Model (sGAM) for permeability and Probabilistic Neural Networks (PNN) for Lithofacies prediction.Firstly, the Probabilistic Neural Networks was adopted for modelling and prediction the continuous and discrete Lithofacies distribution. The classified Lithofacies were considered as a discrete independent variable in core permeability modelling in order to provide different model fits given each Lithofacies type to capture the permeability variation. Then, GLM and sGAM models were applied to build the statistical modelling and create the relationship between core permeability and the explanatory variables of well logs and Lithofacies. GLM considers the maximum likelihood function to estimate the coefficients; however, sGAM considers a sum of nonparametric smoothing functions to identify nonlinear relationships depending on the degree of smoothing. The cubic spline function provides the closest fit as it minimizes a penalized negative log-likelihood function, which represents the smooth terms, by minimizing of an internal generalized cross validation function by iteratively reweighted least squares.In sGAM results, Root Mean Square Prediction Error (RMSPE) and the R-squared have better values than GLM especially in the reduced models. The stepwise elimination was considered to find the best predictors subset in GLM; nevertheless, the non-influential predictors in sGAM were recognized and treated as splines smoothed term to ensure rejection for the null hypothesis and ensure the confidence interval to be greater than 95%. The sGAM model has led to overcome the multicollinearity that was available between one pair of the predictors by using the smoothed terms. All the multivariate statistics analyses of Lithofacies classification and permeability modelling with results visualizations were done through R, the most powerful open-source statistical computing languages.
New Engineering Solution Applied in SUCO Gulf of Suez for Maximizing Usage of Offshore Platforms to Drill Four Times More the Number of Wells From the Same Slot
Authors: Magdy Ramy , Yosri Karem 
Published: September 2015

Abstract
This paper is to highlight the engineering advance method had been successfully applied in Gulf of Suez, Red Sea, Egypt, well, January 2014. This new method enables to use the same slot for several slot recovery operations rather than only one slot recovery. The Deflecting Conductor Shoe is made as a subsea diverting tool. The conventional size ranging from 24” to 30” depending on the platform's dimensions and restrictions. Using a DCS with bigger sizes designed to match the platform's levels to result in the minimum angle at seabed, and to permit for conductor movement horizontally. Also to avoid the magnetic effect at the seabed a mechanical gyro used to determine Azimuth. The spacing between the conductors at the seabed is designed in pattern to allow for best anti-collision results, and more number of wells. The modification on the DCS is by the controlled azimuth of exit, the diameter and the new conductor inclination at the seabed. The most important feature in this design is the ability to engage with a spear from the inside in the future, and turn it to the desired direction considering collision with nearby wells, and with applying the method of drill and drive the risk of hitting nearby wells had vastly decreased and the ability to correct the well path increased by using motors. Using this design will push the platform life within the increased production and in the same time saves the cost to install standalone wells or to establish new platforms extensions which enhances the investment cost for wells on old fields. This means an overall revival of old platforms and old slots whilst making the best use of reservoir potential reserves which were difficult to be achieved with minimal cost. Using this new design, each slot on the platform can be used for multiple slot recoveries, up to five. This design is a modification on the methodology of using the DCS tool which is still conventionally used by major Oil and Gas companies.
Improve Predictions of Petroleum Type and Property Distributions in Reservoirs
Authors: Bouhlel Aziza Moumen 
Published: September 2015

Abstract
Petroleum system modeling has mostly been the preserve of exploration departments in major oil companies, which have the specialist resources to execute these studies. However, as it is a dynamic tool for petroleum system analysis, it also has significant applications in the development stages.
It may provide information on several different aspects of the areas surrounding a discovery: show which other closures were located on the same migration pathways from the same source and highlight the likely oil and gas distributions in these closures.show which satellite accumulations were effective traps and their hydrocarbon composition.The chance that the structure has been flushed with another hydrocarbon type, breached and re-charged, or only contains residual hydrocarbon may also be predicted.
The compositional information from a 3D petroleum system model can be valuable in: Planning appraisal and satellite exploration drilling,Facilities planning where the hydrocarbon composition and the number of satellites that will contribute to the plateau are important to design vs. economic decisions, andRelinquishment decisions.
A discovery well has encountered oil and there is a significant volume of the reservoir updip of the well. 3D petroleum system modeling can be used in determining the possibility of a gas cap and the necessity of the investment in an updip appraisal well. Furthermore with multiple compartments of which only one has been tested the understanding of the effectiveness of the fault seal is critical to determine if the closure may have different hydrocarbon compositions.
The 3D petroleum system modeling can prioritize appraisal drilling to test structures that are most likely to have the desired fluid fill. Furthermore in the case of parts of the concession area has to be relinquished the 3D petroleum system modeling can be used to determine which areas has the lowest economical value in the development.
The high-resolution charge, thermal and pressure histories are important boundary conditions which are required to understand the genesis of the field and the original properties of the oils, and then to obtain an improved understanding of the conditions under which the development hydrocarbons could have taken place (e.g.biodegradation, multi-phase hydrocarbon filling, thermal maturation, water washing, gravitational segregation, hydrocarbon migration along faults, etc).
This provides the best possible definition of the charge, temperature and pressure histories, which will then be available to improve analyses of the genesis and distribution of Hydrocarbons.
Revisiting Reaction Kinetics and Diffusion Rate of Dolomitic Rock with HCl
Authors: Khalid Muhammad Ali , Sultan Abdullah , Qiu Xiangdong 
Published: September 2015

Abstract
Diffusion coefficient (De) is an important parameter used in both matrix acidizing and acid fracturing job design. There are two major limitations of conventional lab practices. Firstly, De is obtained at 1000 psi (or below) system pressure, which is too low to represent realistic reservoir conditions. Secondly, De obtained from conventional lab practice is based on fresh acid, which largely ignores the impact of reaction products, especially CO2.
Herein, we investigate the effects of both pressure and reaction products on De of HCl acid reacting with dolomite using fresh acid (15 wt. %) and various spent acid concentrations (12.5, 10 and 7.5 wt. %). A customized rotating disk apparatus was used to obtain the reaction kinetics data at pressure conditions of 1000 and 3000 psi at various disk rotational speeds (250 – 1250 rpm) at 150 °F. Samples of the reacted acid were collected and analyzed using Atomic Absorption Spectroscopy. In addition, the disks were scanned using X-ray micro computed tomography to characterize the 3D image of the disks.
Our experimental results showed that at equal HCl concentration levels, De was significantly decreased at elevated pressures, due to the impact of CO2 produced by the HCl-carbonate reaction. There was approximately 23% decrease in the diffusion coefficient value when compared with 1000 psi results for HCl/dolomite reaction. On the other hand, when the fresh acid was spent to 12.5 wt. %, there was a slight decrease in the diffusion coefficient results because of the slow reaction rate of dolomite. Moreover, HCl/dolomite reaction was mass transfer limited at low disk rotational speeds and surface reaction limited at high disk rotational speeds. In addition, diffusion coefficient was significantly affected by rock porosity due to variation in surface reaction area which caused increase in dissolution rates as observed by Micro XCT images of the reacted disk.
Rotating Disk experimentation have been used for many years to describe acid reactivity. Literature suggests very few have been conducted under sufficient pressure to represent reservoir conditions. Thus, in order to properly design the acid treatment jobs, the De of acid acquired from high-pressure and various spent acid conditions should be used to provide more reliable parameters estimation such as acid injection rate, volume and pumping schedule leading to more accurate production forecast.
Acidizing of High Temperature and Highly Sensitive Multilayered Carbonate Well with Aminopolycarboxylic Acid Low-pH Fluid: Field Implementation and Laboratory Validation
Authors: Reyes Enrique A. , Rispler Keith , Davis John , Stimatze Russell , Ouedraogo Martial , Beuterbaugh Aaron , LaBlanc Alyssa , Williams Wade , Rees Steve , Bungo Feliciano , Kintomba Pedro , Aguiar Inacio , Morais Elvira De 
Published: September 2015

Abstract
During effective acid stimulation of mature producing wells, operators often face challenges in terms of achieving sustained production increases. Such challenges in formations subjected to acid stimulation in offshore West Africa include high temperatures (305°F), low reservoir pressure (0.22 psi/ft), highly heterogeneous multilayered formations with large perforated intervals (greater than 1,300 ft net and 2,400 ft gross), and scale in the wellbore, perforations, and sometimes in the near-wellbore area (NWA). Wells in this area, when treated with conventional acid systems based on hydrochloric acid (HCl), only sustain the productivity increase for very short periods. Such conventional acid systems have been based on 7.5% HCl and 10% acetic acid (AcOH) with high loadings of corrosion inhibitor, iron sequestering agents, demulsifiers, and antisludge agents.
This approach has constraints that can potentially include the following:
Ineffective stimulation attributed to fast acid reaction rates Limited penetration of live acid Rock disintegration Damage from reprecipitation of acid reaction products, such as iron and mineral fines from wellbore scale Damage from high corrosion inhibitor loading Fluids (stimulation and reservoir) incompatibility
The use of a newly developed aminopolycarboxylic acid (APCA) based stimulation fluid provides advantages that circumvent these constraints. The introduced technology delivers a stimulation system that provides deeper stimulation treatments because of lower reaction rates and potentially a more effective wormhole type of reaction for the reservoirs' characteristics. This stimulation fluid also chelates reaction products to help enable superior cleanup of the acid system. This system also requires lower loadings of corrosion inhibitors, demulsifiers, and antisludge agents, and is more compatible with formation lithology, lowering the risk of formation damage.
Laser Drilling Using Nd:YAG on Limestone, Sandstone and Shale Samples: ROP Estimation and the Development of a Constant ROP Drilling System
Authors: Hafez Ahmed , Ibrahim El-Sayed , Omar El-Said , Seif-Eddeen Fateen , Beshay Karam 
Published: September 2015

Abstract
Background/Scope: Mechanical drilling, the gold standard to reach oil and gas reservoirs, is associated with drilling risks and increased time and costs. Laser drilling has emerged as a potential new drilling tool. However, studies about its practical applications are limited. This study investigates the feasibility and performance of laser technology in drilling oil wells.
Methods: Core samples from the three lithologies were irradiated with Nd:YAG laser at different power intensities and exposure times while holding other parameters constant. Some core samples were saturated with brine to investigate the effect of fluid saturation. We developed a novel laser drilling system that enables users to input the lithology of encountered formations and output the power intensity needed to be drawn from the electric source to maintain the constant ROP.
Results: The Nd:YAG laser beam fully penetrated the cores in all the study trials conducted in shale. In limestone, the laser beam fully penetrated the cores in 5/13 trials and partially penetrated them in 7 trials. The experiments could not be performed in sandstone due to rough surfaces and high porosity. The ROP values ranged between 58 and 66 ft/hr (mean 62.4 ±5.3 ft/hr) in shale and between 221.7 and 460.6 ft/hr (mean 328.5±71.5 ft/hr ft/hr) in limestone. The specific energy values ranged between 650 and 5433 KJ/cm3 (mean 2885.1±1525.8 KJ/cm3) for the limestone samples. A statistically significant inverse correlation was observed between laser energy and ROP (r=-0.952, P&lt;0.001). The developed software was tested and validated.
Added value: The study provides further evidence that laser drilling technology is a promising new technology for oil well drilling. The current study utilized high specific power laser which has not been previously used and developed a novel computer based constant ROP laser system. The rock removal mechanism should be shifted away from melting to spallation to achieve an efficient laser drilling mechanism through the optimization of the laser specific power and decreasing the specific energy during rock removal. Laser beam reflection, sample thickness and fluid saturation were identified as potential factors that influence the efficiency and performance of the laser drilling operation.
A New Method of Pressure Buildup Analysis for a Well in a Multiwell Reservoir
Authors: Deng Qi , Nie Ren-shi , Jia Yong-lu , Wang Xiao-lu , Chen Yang-yang , Xiong Yu 
Published: September 2015

Abstract
This study presents a general method for analyzing pressure buildup data from a well located in a multiwell reservoir, especially in a special case of pressure buildup test which the testing well and adjoining wells are all shutting in at the same time. On this basis, the effect of multiwell interference on pressure buildup curve is analyzed. The method is obtained with the superposition principle, and is general in dealing with any combination of producing, injecting or shutting in conditions of testing well and adjoining wells. Pressure and the pressure derivative log-log new type curves are drawn up. Sensitivities of the type curves affected by different conditions of testing well and adjoining wells(producing, injecting or shutting in) and different parameters are analyzed, including the well spacing, ratio of the multiwell production and production/injection time, which are the main parameters that can reflect the interference of wells. It is shown that the multiwell interference exercises a significant influence on pressure derivative log-log curves of pressure buildup test. It can be summarized in following aspects: firstly, when the adjoining wells are producing, pressure derivative curves are in decline. Secondly, when the adjoining wells are shutting in, pressure derivative curves start to upward. Thirdly, well spacing has an influence on the time of interference on curves, and the ratio of the multiwell production affects the variability of the curves. Fourthly, the way to reducing multiwell interference impact on curves is made adjoining unchanged. Fieldcase buildup analyses in Sebei Gas Field which has a special case of pressure buildup test which the testing well and adjoining wells are all shutting in at the same time show the applicability of the new method, and the type curves had been validated by example. It is indicated that if the multiwell interference is not considered for well test analysis, it will lead to erroneous analyses especially in boundary identification. The novelty of the new method is in the ability to analyze pressure buildup test by different kinds of multiwell interference, and can obtain formation parameter more precisely.
Using Artificial Intelligence in Estimating Oil Recovery Factor
Authors: Noureldien Darhim M. , El-Banbi Ahmed H. 
Published: September 2015

Abstract
Oil and Gas companies are always concerned with continuously evaluating reserves of their assets. Calculating reserves is not an easy task since it requires full knowledge of many technical and non-technical aspects regarding the reservoir nature, available budget, utilized technology, economical conditions and others. Generally, the most important parameter in calculating the reserve for new fields/reservoirs is the “Recovery Factor”. Therefore, many technical approaches available to estimate hydrocarbon reserves are related to estimation of recovery factor.
Recovery factor considers all the aforementioned technical and non-technical aspects. And because these aspects can be numerous, with some that can be only quantified subjectively, the first step in our approach was to standardize and normalize many of these aspects in order to formulate them into digital values to be used in Neural Network algorithms. We gathered all those aspects and classified them into two main categories: Quantitative parameters and Qualitative parameters. Quantitative parameters are normally available in digits (e.g. permeability, porosity, net-to-gross, reservoir pressure… etc.). Nevertheless, this is not the case in handling the Qualitative parameters since parameters like Technology, Asset Remoteness and reservoir structure complexity are not normally represented in digits.
By using wide range of actual fields' data, we had a very good calibration and control points on the algorithm we are going to use. These data include almost all the governing parameters such as Asset Economics, Technology, Facilities, Start of Production, Number of Wells, Reservoir Architecture, Rock and Fluid Properties, Reservoir Energy and others. Since some of these aspects may be hard to find, we generated two well-trained Artificial Neural Network (ANNs): (1) Simple NN includes a few “easy-to-know” basic data, and (2) Sophisticated NN that includes many advanced data with reasonable accuracy. These NNs were taught with more than 150 lessons at which the inputs (lessons) were the aforementioned “parameters” and the output was the “Recovery Factor”.
Testing both the simple and sophisticated networks showed prediction capabilities of 9.5% and 8.0% of actual recovery factor, respectively.
First High-Rate Stimulation Treatment Through Coiled Tubing with Real-Time Downhole Monitoring—A Story of Success
Authors: Al-Thiyabi Adel , Al-Ruwaily Abdulaziz , Mahmood Sajid X , Kneina Mohammed Aiman , Molero Nestor , Ahmed Danish , AM Afsal , Ortega Ruben 
Published: September 2015

Abstract
Over the last 10 years, matrix stimulation of multilateral wells has been one of the most fascinating and technology-driven interventions in the oil and gas industry due to the several challenges involved in this kind of operation. Overcoming these challenges, which include lateral identification and accessibility, reservoir assessment, and accurate placement of stimulation fluids, has encouraged operators and manufacturing and service companies to develop innovative techniques and novel technologies.
In Saudi Arabia, coiled tubing (CT) equipped with real-time downhole measurements and a multilateral identification tool (LIT) has been one of the most valuable technologies to enhance the interventions in multilateral wells. Initially, the ability to monitor real-time data enabled a more efficient operation of the LIT, as well as optimizing and properly placing the stimulation treatment fluids by avoiding the identified high-intake zones across each lateral.
Most recently, the incorporation of gamma ray tool into the real-time downhole measurements package allowed a faster identification of each lateral and accurate depth correlation for pinpoint acid stimulation; nevertheless, when this technology was deployed, pumping rates were significantly limited to a maximum of 2.0 bbl/min due to limitations on downhole tools and optical fiber installed inside the 2 3/8-in. CT. In some cases, this barrier also represented a drawback for optimum fluid penetration and efficient diversion across the zone of interest during the stimulation treatment.
This paper documents the first worldwide applications of the enhanced version of a real-time downhole measurements package deployed on 2 3/8-in. CT for the successful matrix stimulation of a multilateral power injector well in Saudi Arabia, where the barrier of 2.0 bbl/min was far exceeded while maintaining intact all downhole readings. The operation represented a significant increase in operational efficiency and set a new record for this technology. A total of 4,585 bbl of stimulation fluids were injected across the open hole laterals (7,685-ft combined on both wells) at maximum rate achieved of 4.6 bbl/min, which were successfully accessed with the use of the LIT in a single run without the need to pull out the CT to surface.
The use of enhanced the real-time downhole measurements package reduced the operational time by almost 50%, enabled more effective formation damage removal by injecting stimulation fluids at a higher rate, provided real-time depth correlation, verified access via gamma ray to each lateral without the need to tag total depth, and resulted in a tangible cost reduction.