bluuebunny/crossref_metadata_2025_split huggingface dataset:
Discrete Element Simulation of Induced Damaged Zones in Perforation of Deep Gas Reservoirs
Authors: Asadi M. S. , Sarmadivaleh M.. , Nabipour A.. , Sabogal J.. , Rasouli V.. 
Published: January 2010

AbstractPerforation job consists of creating holes in the near-wellbore formation by shooting the perforation agent through the formation in order to establish fluid communication between the wellbore and hydrocarbon reservoir. During this process, some degree of damage occurs in the rock surrounding the perforated tunnel. Determining perforation-induced damage to the reservoir rock and its ultimate impact on the well productivity is of particular interest to the industry.A discrete element-based numerical simulator was employed in this work to evaluate stress redistribution and failure zones around a perforation tunnel in a 2D plane. Formation was simulated as an assembly of densely packed particles bonded together. Macro-mechanical properties of the rock were estimated by changing the micro-parameters in several simulated biaxial tests. The perforation was simulated by shooting an external body penetrating through the wellbore wall in a high velocity, which generates the perforation tunnel as a result of the particle bonds being broken. Shear and tensile failures are expected to develop around the perforation tunnel.The extent of the damaged zone (EDZ) and the depth of penetration (DOP) in a perforation job are important parameters which are influenced by formation mechanical properties, in-situ stress magnitude and direction and the perforation agent size and velocity. In this paper the effect of these parameters are studied by conducting number of sensitivity analyses. The results indicated that the EDZ reduces as formation strength increases and this effect is lesser if formation is perforated at maximum horizontal stress direction. Also, it was seen that both EDZ and DOP reduce as formation grain size increases. Larger perforation agents resulted in a lesser DOP but wider EDZ.
Thermomagnetic Analyses of the Permeability Controlling Minerals in Red and White Sandstones in Deep Tight Gas Reservoirs: Implications for Downhole Measurements
Authors: Ali Arfan , Potter David K. 
Published: January 2010

Abstract
Our recent work on deep tight gas reservoirs containing red and white sandstones (Potter et al., 2009) has shown that the presence of small amounts of hematite in reservoir samples has a dramatic effect on permeability. Such conclusions were made using laboratory based low and high field magnetic susceptibility measurements on reservoir rock samples and by comparing these measurements with the permeability data. These rapid, non-destructive magnetic measurements have previously been applied in clastic reservoir samples (Potter, 2005, 2007; Ivakhnenko, 2006; Ivakhnenko and Potter, 2006, 2008; Potter and Ivakhnenko 2007, 2008) and carbonate reservoir samples (AlGhamdi, 2006; Potter et al 2008). However, such laboratory based analyses are not representative of the downhole in-situ conditions, especially in deep gas reservoirs where temperature can reach quite high values. Typical tight gas reservoir depths can reach to about 4000m (Abu-Shanab et al 2005) and 6000m (Jianming et al 2008) and the equivalent temperatures would measure 131 °C and 192 °C respectively (Mayer-Gurr, 1976).
This paper investigates the in-situ magnetic properties of permeability controlling reservoir minerals (hematite and illite in this case) via laboratory experiments to model downhole conditions. We perform magnetic hysteresis measurements at various temperatures in order to 1) quantify mineralogy and 2) to show changes in the magnetic behaviour of these minerals at in-situ downhole conditions. From these measurements, we are able to show whether the mineralogy and/or domain state of these permeability controlling minerals is likely to change with temperature in the deep gas reservoirs. This can have a major impact on permeability.
We also show some results from another red and white tight gas reservoir where there is a strong correlation between core permeability and magnetic susceptibility data. In this particular reservoir, the presence of siderite in the white sections of the core greatly improves permeability. Once again for this reservoir, the permeability is low in red sections of the core due to the presence of hematite.
How to Define a New Higher Strength Drill Pipe for Maximizing Safety
Authors: Sévignon Anne , El Bachiri Kamal , Gateaud Arnaud , Flores Vincent , Marchebois Hervé 
Published: January 2010

Abstract
The evolution of drilling programs has driven the industry to develop more suitable solutions adapted to extreme and aggressive conditions such as Sour Service environments. High strength drill pipe is necessary to achieve these deeper drilling targets because Sulfide Stress Cracking susceptibility is observed even in minimal concentrations of H2S partial pressure.
Due to the astringency of the sour environment, particular precautions have to be defined to select and characterize an adapted Sour Service steel grade. Controlling crucial manufacturing parameters is the key to successfully supplying products for these critical applications. Steel microstructure, chemical composition, cleanliness and heat treatment process control are all important to promote Sulfide Stress Cracking resistance in high strength drill pipe. Moreover, controlled yield strength, restricted hardness and improved fracture toughness are the mechanical parameters enhancing the ability of these drilling products to be used safely and efficiently by drilling contractors and operators in aggressive wells.
This paper presents the latest VAM Drilling solutions in terms of steel chemistries and manufacturing process controls highlighting key parameters that drilling engineers and specifiers should consider when planning sour gas wells. The paper also introduces further developments to be sought for deep and Extended Reach Drilling above current material limits.
Rock Physical Properties Computed from Digital Core and Cuttings with Applications to Deep Gas Exploration and Development
Authors: Li Guoping , Diaz Elizabeth , Nur Amos 
Published: January 2010

Abstract
Digital rock physics involves high-resolution imaging of rocks, creation of 3D digital (or virtual) rocks, and sophisticated rock property computations. The state-of-the-art CT scanners currently in use allow complicated reservoir rocks to be imaged at resolutions ranging from +50 microns (μm) to a few nano-meters, suitable for analyzing conventional as well as unconventional rocks like tight sandstones, carbonates and shales. Precise separation and capture of the actual pore space in a rock and its solid matrix enables numerical simulations of multi-phase fluid flows within the pores, and makes possible fast and accurate computations of essential rock properties. Key reservoir parameters, such as porosity, absolute and relative permeability, can be computed within a few hours up to a couple of weeks.
Unlike traditional physical measurements, digital imaging-based computational rock physics is not constrained by the shape and size of rock samples under investigation, and therefore can be applied to while-drilling cuttings analysis, an important consideration for expensive deep gas drilling.
Such technologies are particularly suitable for complex reservoir characterization and resource assessment for unconventional tight gas sand and/or shale exploration and exploitation, for this type of reservoirs often, if not always, exhibit extreme heterogeneities in flow characteristics.
Some examples of practical applications include but are not limited to: detailed pore geometry (pore size, connectivity and distributions) study, deterministic volumetric appraisal for ultimate gas resources and risk assessment, flow simulations at pore scales, drill cuttings rock physics (strength, Young's modulus, porosity-permeability profiling) to guide vertical and horizontal well stimulation engineering, effects of clay, minerals and diagenetic processes, partial water saturation, and fracture network characterization.
In this paper, the concepts and procedure of digital rock physics will be fully introduced. In addition, we will present some case studies from unconventional plays to demonstrate its applicability.
Field Application of Applying the Best Practice in Proppant Fracturing Shaly Sand Formation
Authors: Johnson Dan , Zaki Said , Mendez Alfredo , Kuchinski Robert , Amer Mostafa Amin 
Published: January 2010

Abstract
This paper describes a field example of Planning to frac tight Shaly sand formation which offers a unique challenge for fluids, equipment and personnel. The main objective is to maximize the value of the field over its productive lifetime. The primary benefit from these applications is the utilization of the equipment capabilities and the fluids properties to get the best possible fracture length and conductivity for optimizing field-development economics.
The objective of the paper is to make available the information needed to do the proper preparation and execution for similar well conditions in the area. Starting with the proper field study to have the best candidate for the hydraulic fracturing was a key parameter for the success of the job. This field has started with initial pressure of 2400 psi and total potential of 7000 BOPD. Other consideration concerning the lithology characteristic of the reservoir, the tight shaly sand formation will not produce at its best potential without the high pressure proppant frac. The selection of the fluid suitable for this job was mainly to have to best properties and stable fluid to carry the proppant, not damaging to the formation, not to cause any clay swelling, easy to X-Link and easy to break after the job. Also the selection of the equipments to give the proper rate and pressure with fully remote control from the data van was considered to have a successful job.
Mechanical Earth Modeling Improves Drilling Efficiency and Reduces Non-Productive Time (NPT)
Authors: Moazzeni Alireza , Nabaei Mohammad , Shahbazi Khalil , Shadravan Arash 
Published: January 2010

Abstract
As time goes by, increase in world energy demand forced oil and gas companies to drill deeper in order to produce more oil and gas for quenching the thirst of human needs. This requires drilling layers with various lithologies with variable characteristics and dealing with more drilling problems as going deeper. Mechanical Earth Model (MEM) should be developed to bypass drilling problems. This model will be used for analyzing instability of the wellbore wall, selecting optimized azimuth and inclination for well trajectory, optimized perforation, sand production analysis and stimulation operation design. In this paper, a mechanical earth model is developed for one of the Iranian fields in Middle East and then drilling data are employed to optimize well trajectory based on wellbore stability models and higher penetration rate. Theoretical results show remarkable increase in drilling performance and applying optimized parameters will shorten drilling operation.
Uncertainty Analysis in Unconfined Rock Compressive Strength Prediction
Authors: Nabaei Mohammad , Shahbazi Khalil , Shadravan Arash 
Published: January 2010

AbstractLots of sources can be used to derive unconfined rock compressive strength (UCS) along the wellbore as a key input of failure criteria for wellbore stability analysis. Laboratory tests are the most accurate methods to obtain rock strength which mainly are destructive and result in a set of discrete data. On the other hand, non-destructive methods (log based approaches), deliver a continuous rock strength log, however, the accuracy of these techniques is still dubious and they should be calibrated with lab data. If the evaluated rock strength contains some errors, final mud weight window will be affected by these errors which lead to inaccurate mud weight selection for safe drilling operation and consequently increase in total well cost. Whole data in UCS log shall be multiplied or added by a number to match laboratory results. This calibration approach may superficially show good match between results from log and laboratory, though all data may not represent real UCS and show same uncertainty. In this paper, a modified calibration approach based on lithology, compaction, fluid content and porosity is proposed for calibration of UCS logs. Performed cross validation results show a good match between laboratory data and modified UCS profile.
The Role of Resistivity Image Logs in Deep Natural Gas Reservoirs
Authors: Kalathingal Paul , Kuchinski Robert 
Published: January 2010

Abstract
Occurrences of deep gas are commonly found in clastic reservoir rocks. The great depths of these reservoir rocks often result in rocks with low porosity and poor permeability. In order for these reservoirs to be productive, natural fracture systems or induced fractures from stimulation processes are required to allow gas to flow to the well bore. In order to assess the potential of these reservoirs, explorationists around the world depend on data acquired from resistivity imaging tools to visualize the fractures.
This paper will discuss fracture analysis using resistivity image data that provides better reservoir characterization on fractured reservoir than the normal open hole logs. Image data has higher resolution compared to the basic open hole data, and allows for fracture visualization down to 2mm. Petrophysical analysis using basic open hole data will average out the fine details of the fracture and its effects on porosity and permeability. Image based petrophysics known as “Image petrophysics” allows for the conversion of high resolution image data to high resolution petrophysical properties which provides greater understanding of the impact of the fractures on reservoir characterization. The use of Image data calibrated with either core data or basic open hole data allows for the derivation of high resolution porosity distribution. Permeability derivation can also be achieved using image data calibrated with core data. This process can also be extrapolated to wells that are un-cored.
This paper will also discuss the challenges of acquiring image data from these deep environments by employing memory based image tools that can be conveyed using a broad range of conveyance techniques.
A Systematic Approach to the Integration of Upper and Lower Completions: A Strategy for Deep Gas Applications
Authors: Jones Richard 
Published: January 2010

Abstract
In designing completions for deep, high-temperature applications, operators have historically concentrated their efforts on two sections, either the upper or lower completion. By focusing solely on the two sections, operators have been unable to maximize the compatibility of the entire well completion. An organized, well-planned, incremental approach to the two components of the well completion leads to safer, more efficient installations and long-term operability. This paper will discuss the challenges associated with deep gas completions and how a systematic approach to overall completion design can save time and money while establishing a safe installation process. In addition, it will cover the emerging technologies in the completions field for the deep gas marketplace and how they can improve completion design effectiveness.
Stimulating Khuff Gas Wells with Smart Fluid Placement
Authors: Garzon Francisco , Amorocho Jose Ricardo , Al-Harbi Moataz , Al-Shammari Nayef S. , Al-Ruwaished Azmi , Ayub Mohammed , Kharrat Wassim , Burgrov Vsevolod , Jacobsen Jan , Brown George , Noya Vidal 
Published: January 2010

AbstractThe objective of many matrix acidizing treatments in the Khuff carbonate formations is to remove drilling damage and enhance productivity after the drilling process. Open hole and multilateral completed wells, present several challenges that prevent an optimum intervention with coiled tubing (CT). Traditional practices have been limited to spot stages of pre-flushes, acid, and diversion systems in front of the formation from toe to heel without proper control over the placement process.Using an innovative workflow, interpretation of distributed temperature surveys (DTS) responses, correlated with reservoir data, assists in selectively placing fluids, maximizing the contact of stimulation fluids with the targeted formation sections. Two field applications, in dual-lateral horizontal open hole gas producers, that demonstrate how to optimize a stimulation treatment as it occurs, were implemented in a field in the Kingdom of Saudi Arabia.In both cases, selective access to pay zones in each lateral was confirmed with DTS profiles. Following the pre-flush and the first acid pass, DTS measurements indicated acid effect over the permeable zones but also detected fluid movement towards non gas bearing thief zones. Foam and energized visco-elastic diverting acid fluids were used to divert acid to the target zones avoiding the lost of all stimulation fluids to the toe in one case and to the heel in the other well. After treatment, the gas production increased from zero to more than two times the expected rate in both wells.Understanding of the flow patterns as fluids are placed in the wellbore was possible. Changes to the fluid placement schedule during the job resulted in optimum acid coverage and efficient diversion confirmed by the downhole measurements. The identification of the thief zones was critical to avoid wasting fluids. This experience, the first ever gas wells in Middle East, represents an opportunity for un-locking production potential in similar gas developments.
Simulating Model to Reduce Detrimental Acidizing in Tabnak Gas Field
Authors: Farrokhrouz M , Asef M R 
Published: January 2010

AbstractDalan and Kangan formations are the most important host gas reservoirs in Iran. These geological formations are extended to other regions, and they are famous as Khuff formation in the Middle East. They are mainly composed of limestone and dolomite with some inter-beds of shale. So far many reservoirs in Iran are hosted by Asmari carbonate formation. However, acidizing in other hydrocarbon formations (Asmari formation) is accomplished similarly. Conventional acidizing operations were performed on Dalan and Kangan formations in one of the gas fields in south of Iran. Substantial reduction of produced gas was observed over a short period of time. For this reason a comprehensive engineering geological site investigation was accomplished to explain the symptoms and avoid possible further deterioration. Connate water samples from the well while production, showed some unexpected results. Different chokes were tested to see if the amount of impurities in the sample would change. To reduce the amount of water accompanied with produced gas, a different choke was selected; but the result was not satisfactory enough based on refinery report.Therefore, the geological features of the well were gathered based on well sketch and logging data. The phase equilibrium of the reservoir rock before and after acidizing was simulated using a software. The results of chemical lab were analyzed to check the kind of the salts in the well. Laboratory chemical experiments were accomplished to explore produced salts in the well. Further investigation revealed that the choke size was not suitable, and inappropriate acidizing could deteriorate the situation. Based on this research, a number of recommendations were suggested to improve the circumstances of production rate. The authors suggested more carefully designed techniques of acidizing to be applied. The results of this research may be used to prevent geomechanical destabilization around the wellbore in similar cases.
Field Trials of a Novel Fiber-Laden Self-Diverting Acid System for Carbonates in Saudi Arabia
Authors: Leal Jauregui Jairo A.. , Malik Ataur R.. , Walter Nunez Garcia , Solares Ricardo J.. , Tomislav Bukovac , Gurmen Nihat M.. 
Published: January 2010

Abstract
Acid stimulation of carbonate formations using hydrochloric (HCl) acid-based systems to improve hydrocarbon production or water injection has been a common practice since the early days of the oil and gas industry. The challenge of achieving full zonal coverage with the stimulation fluid still persists. This task is even more difficult in highly slanted layered, naturally fractured reservoirs exhibiting high permeability and porosity contrast.
During acid stimulation treatments, the fluid has a natural tendency to take the path of least resistance, penetrating layers with the highest porosity and permeability while little or no acid is injected into lower-quality zones. Excessive fluid loss to these high-quality thief zones results in a nonhomogenous distribution of stimulation fluids across the targeted interval. These higher-quality zones are essentially over stimulated, allowing them to contribute the most to post-treatment production. This leaves neighboring lower-quality zones unstimulated, preventing them from reaching their maximum potential.
A novel fiber-laden polymer-free self-diverting acid system was introduced in Saudi Aramco to improve zonal coverage across the entire interval of interest in vertical and highly slanted wells during stimulation treatments. This diversion system combines fiber and a self-diverting acid, which utilizes a nondamaging viscoelastic surfactant that gels as the acid spends. The combination of the self-diverting acid and fiber enhances the diversion process by combining the aspects of both particulate and viscosity-based diversion techniques. The fluid system has a distinct advantage in that it does not contribute to reservoir damage as the viscoelastic surfactant will break down upon contact with hydrocarbons, and the fiber will dissolve with time and temperature.
The fiber-laden self-diverting acid system has been applied in new developments and producing gas wells in the Khuff reservoir of Saudi Aramco with impressive results. The diversion and acid reaction signatures were evident in the acquired treating pressure plots during acidizing with the fiber-laden polymer-free self-diverting acid system. The initial results indicated substantial pressure responses and excellent gas production performance.
Effective Ways to Avoid Barite Sag and Technologies to Predict Sag in HPHT and Deviated Wells
Authors: Amighi Mohammad Reza , Shahbazi Khalil 
Published: January 2010

Abstract
Barite Sag is an oilfield term used to describe significant density variations while circulating bottoms up after a trip, logging run or other operations that require the mud to remain static for an extended period of time. Sag is caused by static and/or dynamic settling followed by slumping of the weighted material. Static sag, as the name suggests is caused when circulating is stopped for an extended period of time, and the weighting agents begin to settle under the influence of gravity. Due to slumping, dynamic sag occurs frequently in inclined holes. However, the problem has been exacerbated by the increased frequently of high-angle wells with the associated increase in particle settling rate which occurs in an inclined fluid column. The settling of solids is enhanced by convective currents created by density differences in the fluid across the annulus cross section. This effect is frequently referred to as Boycott effect.
This paper presents the most effective ways to avoid the occurrence of barite sag in high-pressure high temperature (HPHT) drilling operations, and in high-angle wells. The ways such as replacing barite by other weighted materials such as Ilmenite or Manganese tetraoxide. Furthermore, it is suggested to use a cesium formate based drilling fluid or polymer-coated ultra-fine barite for drilling HPHT wells. Moreover, different technologies to predict dynamic sag such as, flow loop tests and modified rotational viscometer tests, are introduced.