bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ants Can Do History Matching
Authors: Hajizadeh Yasin 
Published: February 2011

Abstract
This paper introduces a new stochastic approach for automatic history matching based on a continuous Ant Colony Optimization algorithm. Ant Colony Optimization (ACO) is a multi-agent optimization algorithm inspired by the behavior of real ants. ACO is able to solve difficult optimization problems in both discrete and continuous variables. In the ACO algorithm, each artificial ant in the colony searches for good models in different regions of the parameter space and shares information about the quality of the models with other agents. This gradually guides the colony towards models that match the desired behavior – in our case the production history of the reservoir.
The use of ACO in history-matching has been illustrated on PUNQ-S3 reservoir simulation model in North Sea with 45 unknown parameters. This model is fitted to multivariate production data coming from multiple wells. The ACO algorithm is also integrated within a Bayesian framework to quantify uncertainty of the predicted ultimate recovery.
Results confirm that Ant Colony Optimization can be used to generate multiple history-matched reservoir models and accurately predict the final recovery from the reservoir after 16.5 years. We have compared the history matching results of ACO algorithm with the Neighborhood Algorithm (NA) and NA coupled with a geostatistical framework applied to the same problem. This comparison indicates that ACO obtains the history matched models from fewer simulations. We conclude that Ant Colony Optimization is a fast, reliable and promising tool for reservoir history matching and uncertainty quantification.
A Novel Method to Model Water-Flooding via Transfer Function Approach
Authors: Sayyafzadeh Mohammad , Pourafshary Peyman , Rashidi Fariborz 
Published: February 2011

AbstractWater flooding is one of the most economical methods to increase oil recovery. To maximize oil recovery during water-flooding, it is essential to provide a forecast of reservoir performance. Hence, various methods are used to simulate reservoirs. Although grid-based simulation is the most common and accurate method, time-consuming computation and demand for large quantities of data restrict the use of this method.This study presents the development of a new method to predict the performance of water injection based on Transfer Functions (TF). This method is faster since it requires less data and the only requirements are injection and production rates. In this method, it is assumed that a reservoir consists of a combination of black boxes (TFs). The order and arrangement of the TFs are chosen based on the physical condition of the reservoir which is ascertained by checking several cases. The injection and production rates act as input and output signals to these black boxes, respectively. After analyzing input and output signals, unknown parameters of TFs are calculated. Then, it is possible to predict the reservoir performance.Different cases are employed to validate the derived model. The simulation results show a good agreement with those obtained from common grid-based simulators. In addition, we found out that the TF parameters depend on the characteristics and the pattern of different sections of the reservoir.This method is a rapid way to simulate water-flooding and could be a new window to the future of fast simulators. It enables prediction of the performance of water-flooding and optimization of oil production by testing different injection scenarios. The method also provides key parameters such as well connectivity.
Integration of In-Situ Combustion with Solvent Injection - A Detailed Study
Authors: D'Silva Jonathan 
Published: February 2011

AbstractProduction of heavy oil has always been associated with a lot of problems. A major one being the high viscosity of heavy oil due to which it does not flow easily into a producer well. In-Situ techniques like Cyclic Steam Stimulation (CSS), Steam Assisted Gravity Drainage (SAGD), and Vapor Extraction Techniques (VAPEX) are not mutually exclusive and it is becoming increasingly common for wells to be put through one of the techniques followed by the other so as to improve recovery rates.The main purpose of this paper is to discuss the effects of combining the techniques of In-Situ Combustion with heavy hydrocarbon injection on the same heavy oil reservoir.This paper discusses the effects of injecting different hydrocarbon solvents and gives a detailed explanation of this combination technique as an integrated unit, explaining the effects of In-Situ Combustion after hydrocarbon injection and its various advantages over using just a single technique.
Optimizing Production of Tight Gas Wells by Revolutionizing Hydraulic Fracturing
Authors: Ahmed Mansoor , Shar Amjad Hussain , Khidri Muzammil Ahmed 
Published: February 2011

Abstract
Tight gas wells are the wells having low permeability and the production of gas from these tight formations is the key issue in the industry. This paper includes the calculations, simulation work and enhanced engineering work to increase productivity along with the case studies.
Hydraulic Fracturing is usually conducted to resolve these kinds of situations. But the productivity can shoot up to 45-55%. It is done by revolutionizing the conventional hydraulic frzcturing through flow channel creation by enhancing proppant qualities like its strength and roundness, by lowering its crush and gel loading and improving gel breakers. Perforations are engineered and pumping technique and perforation strategy are combined causing channel formation. The combination of enhanced conductivity and effective fracture half length enables greater hydrocarbon recovery. Instead of flowing through proppant pack hydrocarbon flow through the channels created by proppant pillars giving effectively infinite conductivity and better fluids and polymer recovery and less fracture face damage. Via these techniques traditional losses in proppant pack conductivity from crushing, fines, fluid damage multiphase flow and non-darcy effects are eliminated meaning optimized production.
A Literature Analysis of the Coiled-tubing Drilling Processes
Authors: Kumar Sarvesh , Raj Parimal , Mathur Bakul 
Published: February 2011

AbstractEffectively managing resources encompasses accurate engineering of target formations and prudent execution of project capital. Attaining both requires employing current technologies and implementing efficient operations, especially with today's challenging drilling environment and economic climate. The influence of improved technologies and the latest operational developments has lead to a significant impact in the arena of coiled-tubing drilling operations. Coiled-tubing drilling is a rapidly growing technology that has been used for various applications nowadays such as drilling shallow new wells, re-entry applications, sidetracking etc. This paper summarizes the hypotheses and theories relating to the causes and expectations of Coiled-tubing drilling in various reservoirs worldwide. The intent of the paper is to:Provide a concise compendium to the current understanding of the coiled-tubing drilling operations.Provide a comprehensive single-source review of the various projects successfully completed in the area and lessons learned.Help operators develop operational and design strategies for current and future projects, as well as to input parameters for simulating current and future projects.
Innovative Reservoir Modeling and Simulation of Unconventional Shale Gas Reservoirs Powered by Microseismic Data
Authors: Fazelipour Waleed 
Published: February 2011

AbstractShale-gas resource plays have started a new era for hydrocarbon exploitation in the energy industry worldwide. Latest advancements in drilling and stimulation are enabling technologies that make production of shale reservoirs economically viable. Multistage hydraulic-fracturing, the key technology to enhanced well performance, creates complex stimulated reservoir volumes, surrounding the wellbore, which are the main contributors to higher production profiles. Understanding the performance of such very tight, low permeability media and associated flow, introduces new challenges. Modern reservoir simulation powered by microseismic information, offers the best techniques to help understand them; evaluate the performance of wells; estimate the ultimate recovery; and help maximize the production.Reservoir simulation provides cost-effective ways of understanding the shale-gas reservoirs behavior, and supplies information operators need to make quicker and better field development decisions. Reservoir simulation technology can optimize hydraulic-fracturing to maximize profitability and realistically simulate its effects in heterogeneous reservoirs involving multiphase, multicomponent fluid-flow and adsorption/desorption mechanisms. This is highly desirable to the industry. Properly describing the hydraulic fractures, their geometry and position; and characterizing reservoir/fracture properties are the main challenges.This innovative work presents integrated workflows that demonstrate effective methodologies for capturing the essential characteristics of shale reservoirs; link seamlessly with microseismic fracture mapping software to import detailed descriptions of hydraulic-fracture attributes; offer flexible gridding schemes and populate the physical properties to enhance modeling of wells stimulated with hydraulic-fracturing. Ultimate conclusions of achievements include help generating more accurate forecasts which are critical for understanding wells performance and maximizing productivity.This research has led to leading-edge reservoir simulation techniques to be utilized by the global E&P industry that enable operators to develop an early understanding of the performance of shale-gas wells where such detailed knowledge is vital to optimizing exploitation economics and estimation of reserves and resource potential.
Optimization of the Design of Transverse Hydraulic Fractures in Horizontal Wells Placed in Dual Porosity Tight Gas Reservoirs
Authors: Gorucu S. E. , Ertekin T.. 
Published: February 2011

AbstractThe exploitation of gas from tight gas reservoirs has been increasing due to the advances in unconventional gas technologies and depletion of conventional gas resources. Drilling horizontal wells and placing transverse hydraulic fractures are needed to produce economically viable amounts of gas from tight sands. In this research, optimization of the design of hydraulically fractured horizontal well placed in naturally fractured tight gas sand reservoir systems was studied. A commercial reservoir simulator is coupled with artificial neural network (ANN) to create an expert system that can be used to design an efficient stimulation strategy. Reservoir simulation was used to generate production profiles of the reservoir system and, then, used to train the artificial neural network system. The ANN tools developed in this project consists of two parts: forward and inverse processes. In the forward process, an input data set that includes well and completion design parameters and reservoir properties is used to create an ANN toolbox to predict the production profile. In the inverse process, several design parameters and the desired production profiles were introduced into the input data to create an ANN toolbox to estimate the optimum design parameters. It is found that in both expert systems, functional links play a significant role in the success of the ANN tool. The results estimated by this developed toolbox can be used as preliminary information about the expected production profiles or the required wellbore and fracture design parameters for different cases.This study shows that natural fracture permeability is the principal factor that determines the magnitude of the production. In addition, overall conductivities of the natural fractures and the hydraulic fractures are important factors affecting production.
Non-Darcy Flow in Tight Gas Reservoir of Travis Peak Formation
Authors: Khlaifat Abdelaziz , Arastoopour Hamid , Qutob Hani 
Published: February 2011

Abstract
The future of the energy sector in the coming years is expected to be significantly affected by unconventional gas resources. Most of the fundamental studies of flow in porous media are focused on the influence of the microscopic geometric structure on the macroscopic parameters. In order to address this question for flow through tight porous medium a series of single phase gas flow experiments were conducted. The considered porous medium sample was slot-and-solution pore type tight sand from the Travis Peak Formation with permeability in microdarcy range and porosity of 7%. Nitrogen and helium were the used gases. Single-phase experiments were conducted at different pressure drops and overburden pressures. They showed that the sample used is very sensitive to overburden pressure. Pore size distribution measurements, by mercury intrusion porosimetry and sorption isotherm, showed the existence of a wide range of pore size (from 0.4 to 400 nm) distribution. Moreover, the single phase gas flow through the sample particularly at low pressure is of Knudsen diffusion type. Thus, the gas molecules may slip at the wall of the capillary and the Klinkenberg formulation may be the approach to describe the deviation from Darcy’s law.
A Permeability Predictive Model Based On Hydraulic Flow Unit for One of Iranian Carbonate Tight Gas Reservoir
Authors: Haghighi Mehdi Bagheripour , Shabaninejad Mehdi , Afsari Khalil 
Published: February 2011

Abstract
Carbonate reservoirs show challenges to engineers and geologists to characterize because of their tendency to be tight and generally heterogeneous due to depositional and Diagenetic processes. The value of permeability is very valuable in dynamic reservoir modeling and simulation. Since permeability measurements during coring are very expensive and hard to be achieved, permeability predictive models are very desirable.
Among the various quantitative rock- typing techniques presented in the literature, the Hydraulic Flow Unit method (RQI/FZI) is more widely used. ‘D’ is a main carbonate formation in one of the giant gas reservoir in Iran. In this study, available routine core and wireline log data from four wells in this formation are assembled to develop Permeability Predictive Model based on Hydraulic Flow Unit.
For this purpose, first whole core data were used to characterize ‘D’ formation by several discrete rock type (DRT) with Hydraulic flow unit concept. Correlation accuracy of each discrete rock type was very good (R2&gt;0.9). It is obvious that permeability can be accurately predicted from porosity if rock type is known. Eight different wireline log data were used to develop a permeability predictive model. For this, the whole log data for all wells were individually interpreted and normalized. After that, the values of the normalized logs were extracted at the exactly core plugs depths for each DRT. A convenient multivariate regression analysis was then performed to develop an explicit mathematical model for predicting permeability in uncored intervals and uncored wells. After some mathematical manipulation, the model was ready to use.
For testing the accuracy and reliability of this predictive model, the core data of one well which exists in the same formation was used. Results show that the permeability of predictive model matched well with the tested cored data in ‘D’ formation.
Well Logging and Formation Evaluation Challenges in the Deepest Well in the Sultanate of Oman (HPHT Tight Sand Reservoirs)
Authors: Al-Mahrooqi Sultan , Mookerjee Abhijit , Walton William , Scholten Sven , Archer Ray , Al-Busaidi Jokha , Al-Busaidi Hafidh 
Published: February 2011

AbstractThe high demand for natural gas in Oman has stimulated new exploration for gas resources that can be developed commercially. The Exploration Directorate in Petroleum Development Oman (PDO) has recently extended its exploration programme into the deeper parts of the sedimentary basins in North Oman. Reservoirs located here, principally in the Amin and Nimr formations, are expected to be tight (low porosity and permeability).Data acquisition and petrophysical evaluation are major challenges when exploring the deep gas plays in North Oman. This is due to the hostile reservoir environment, i.e. high pressure and high temperature (HPHT). Current logging tools (wireline, LWD) are rated for operations up to 175°C and 20,000 psi. Data acquisition becomes significantly challenging as higher temperatures cause the logging tool electronics to fail.This paper describes data acquisition and formation evaluation challenges for the deepest gas well drilled to date in the Fahud Salt Basin in the Sultanate of Oman. The first part of the paper discusses the logging plans, challenges and how, through optimised data acquisition, the objectives of logging programmes have been met. The planning phase started six months prior to well spud to manage the high uncertainty in the prognosed well TD depth and borehole temperature. The final well depth reached was 7145 m AH which is currently Oman’s deepest well. The maximum recorded downhole temperature was 195°C which posed a serious risk to successfully logging the last borehole section. Both LWD and wireline options were implemented and are discussed in the paper. Dual density tools were successfully used to overcome the borehole breakouts whereas flask Resistivity and HPHT tools were used to overcome borehole temperature limitations.The second part of the paper describes formation evaluation methodologies we used in tight reservoirs. Improved porosity and water saturation calculations by integrating data from well logs, drilling, mud logging as well as geochemistry are discussed
Soda Ash as Gypsum Dissolver in 8" Production Line Case Study Gemsa Field, Gulf of Suez, Egypt
Authors: Riad E. H. , Abd-allah K. O. , Sarhan A. H. 
Published: February 2011

Abstract
Water flooding is the hinge pin for Gemsa Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests had indicated probable deposition of calcium sulphate scale on surface and subsurface production equipment. Calcium sulphate scale has been recognized to be a major operational problem. The bad consequences of scale formation comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can’t be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options (1).
Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale.
This paper describes the development and field application of chemical treatment to remove scale in an offshore 8" production line in Gemsa oil field. Continuous precipitation of calcium sulphate scale caused partial plugging of the pipeline. This partial plugging created a back pressure on production wells which decreased the productivity. The field production has been decreased to almost one tenth of the normal field production level.
A thorough investigation was conducted to identify the composition and location of the scale, in order to recommend a suitable chemical to remove the scale, and to assess the effectiveness of the treatment method in the field.
Based on extensive lab studies, Soda Ash was tested and applied in production line to remove the scale efficiently; the program was designed taking into consideration the nature of the scale.
The treatment program included three - staged process:The use of an organic solventThe main treatment (Soda Ash).The post flush stage (15 wt% HCl),
The job results were outstanding, where asProduction increased by about 2,000 BOPDLauncher pressure dropped by about 270 psi.Decrease the back pressure on our producing wells.Additional producing wells into production.Efficient cost /Bbl.
Application of High Resolution Micro-CT Imaging and Pore Network Modeling (PNM) for the Petrophysical Characterization of Tight Gas Reservoirs - A Case History from a Deep Clastic Tight Gas Reservoir in Oman
Authors: Riepe L.. , Suhaimi M. H. , Malaysia M. Kumar , Knackstedt M. A. 
Published: February 2011

Abstract
The paper provides a case history of the application of 3D imaging and Pore Network Modeling (PNM) technology to establish a direct relationship between rock micro-structure parameters from 3D via micro-tomographic images, and the simulation of petrophysical properties of clastic tight gas reservoir rocks in Oman. Tight gas reservoirs exhibit storage and flow characteristics that are intimately tied to the depositional and diagenetic processes. In particular, cores have significant primary and secondary porosity often dominated by clays and slot like pores. Accurately mapping the pore and grain structure and mineralogy in 3D and the interconnectivity of primary and secondary porosity illustrates the role 3D imaging plays in a comprehensive reservoir characterization program.
The computed petrophysical properties (e.g. porosity, permeability, formation resistivity factor, hydraulic radii and drainage capillary pressure) are compared with routine and special core analysis results measured on conventional core samples. The use of 3D micro-tomograms at different scales and PNM provides a quick complimentary method to characterize the distribution and nature of different pore types and matrix components to characterize the static, elastic and dynamic rock properties even on rock fragments (2mm to 1cm diameter) that are not suitable for conventional core analysis techniques.
The presented case history demonstrates that the new 3D PNM technologies can also be successfully applied to the challenging tight gas reservoirs with low porosities and very low permeabilities for comprehensive reservoir characterization to optimize the development scenarios.
Drilling Waste Management: A Case Study of the Drilling Waste Management and Environmental Control in one of the Iranian Offshore Fields
Authors: Razmgir Seyed Mohsen , Afsari Meisam , Amani Mahmod 
Published: February 2011

AbstractIn upstream petroleum industry, one of the major operations that can potentially impact the environment is drilling. A major component of the wastes generated during drilling are the rock cuttings and the drilling fluids. The drilling fluids can have different chemical composition and various additives. Spilled or improperly disposed drilling wastes have the potential to harm plants and animals, and it should be managed to minimize risk to human health and the environment.This paper presents the recent experiences in one of the Iranian offshore fields and their approach to develop and implement fluid wastes treatment and management exercises in drilling operations toward minimum impact on HSE in Khark Island. This paper reviews the drilling process, types of drilling fluid used and their composition and the methods to separate cuttings from drilling fluid.