bluuebunny/crossref_metadata_2025_split huggingface dataset:
Can Proppants Do More Than Hold The Fracture Open?
Authors: Saldungaray Pedro , Palisch Terry , Leasure Josh 
Published: June 2015

Abstract
In the 1940's experimental fracture treatments were performed without proppant. However in most formations unpropped fractures heal quickly with no sustained benefit, and in 1947 river sand was introduced as proppant. The first evolution in proppants came in the 1950's, when river sands started to be replaced by higher quality mined sands from Illinois and Texas. This was the early recognition that employing more uniform, rounder, stronger - and ultimately more conductive proppant - produced larger production gains. From this point on efforts concentrated on improving sand performance and finding new propping materials that could cope with harsher conditions. In the 1960's, petroleum engineers incorporated walnut hulls, glass and plastic beads into frac designs. The 1970's saw the introduction of resin coated proppants and the first commercial bauxite based ceramic proppant, followed by low and intermediate density ceramics in the 1980's. However, throughout this time, proppants still served one primary purpose – to prop open the fractures and provide a conductive flowpath for hydrocarbon production.
Placement of proppant deep into the formation brings a unique opportunity of conveying new functions, additional to the primary roles of keeping the frac mechanically open and providing a conductive path for production enhancement. For decades most proppant development efforts concentrated on developing proppants that could either cope with higher stress and deliver higher conductivity or improve proppant transport via lower density, while minimal effort was put in adding other functionalities. Recently it has been recognized that other functions can be incorporated into manmade proppants during the industrial manufacturing process, thereby exploiting the placement opportunity. These functions might include assuring flow in the production system, providing reservoir surveillance or monitoring fracture properties.
This paper will review the latest technology developments that enable the incorporation of these functions into proppants, including how the new proppant delivered technologies permit users to cost effectively deploy additional functionalities in the initial completion of hydraulically fractured, frac-packed and gravel-packed wells. The paper will also present recent case histories of field implementations of these technologies which illustrate how these high function proppants can reduce overall operating costs, enhance production and diagnose hydraulic fractures.
Chelating Agent for Uniform Filter Cake Removal in Horizontal and Multilateral Wells: Laboratory Analysis and Formation Damage Diagnosis
Authors: Al-Ibrahim Hussain , AlMubarak Tariq , Almubarak Majed , Osode Peter , Bataweel Mohammed , Al-Yami Abdullah 
Published: June 2015

Abstract
An impermeable mud cake layer, created on the formation face while drilling may be favorable for drilling operations but detrimental to well productivity. In vertical high pressure wells the layer is cleaned out while flowing back the well at adequate pressure drawdown. On the other hand, low pressure differential at the sand face in horizontal wells makes well cleanup treatments a necessity. Not all filter cake components are acid soluble. Commonly used inorganic acids and oxidizers are very reactive and cause uneven filter cake removal, which can affect the well's performance. As a result, there was a need to evaluate slow-reacting chemicals that can produce delayed uniform filter cake removal in horizontal wells. These treatment chemicals vary from the nonreactive acid-free microemulsion fluid systems to the weak organic acids, acid precursors, enzymes and chelating agents.
The objective of this paper is to evaluate two chelating agent based treatments, NTA and EDTA, as filter cake removal treatments for a sandstone reservoir utilizing oil based mud (OBM) drill-in fluid (DIF) in Saudi Arabia. Coreflooding experiments were run under reservoir conditions to evaluate fluid-rock interaction. In addition, fluid-fluid compatibility was conducted between chelating agent and drill-in fluids base brines and between the chelating agent and formation fluid using high temperature, high pressure (HTHP) see-through cell. Solubility and static fluid-loss tests were conducted to evaluate the filter cake removal efficiency.
Experimental results indicated that the NTA-based treatment was effective in removing up to 91% of the filter cake uniformly after soaking treatment for 24 hours. Fluid-fluid compatibility tests showed that the NTA-based chelating agent, when mixed with reservoir fluids, was free from precipitation or emulsion. On the contrary, mixing the chelating agent with the DIF carrier brine resulted in severe precipitation of insoluble permanently damaging byproducts. The laboratory study also observed that pH has a direct proportional relationship with the amount of precipitation.
EDTA-based treatment results showed a removal efficiency of 93% after soaking treatment for 90 hours. Fluid-fluid compatibility tests showed that the EDTA-based treatment, when mixed with OBM DIF was free from precipitation or emulsion. On the contrary, mixing the chelating agent with the reservoir formation water resulted in severe precipitation of insoluble permanently damaging byproducts.
Laboratory Evaluation of Different Mode of Supercritical CO2 Miscible Flooding for Carbonate Rocks
Authors: AlOtaibi Fawaz M. , Zhou Xianmin , Kokal Sunil L. 
Published: June 2015

Abstract
Field application of supercritical CO2 (sc- CO2) miscible flooding continues to grow. Optimization of sc- CO2 injection during miscible flooding modes represents one of the dominant factors affecting its performance in carbonate oil reservoirs. The main objective of this study was to investigate the impact of different modes of sc- CO2 miscible injection on oil recovery and injectivity in carbonate rocks. Several modes of sc- CO2 injection modes were investigated including continuous CO2 miscible flooding, water-alternating-gas (WAG), and tapered WAG injection. Five coreflooding experiments were conducted to evaluate oil recovery for different modes of CO2 injection under reservoir conditions. Composite cores of 25 cm length from a specific, producing carbonate reservoir were used in the study. Both horizontal and vertical coreflooding experiments of continuous CO2 injection mode were carried out to compare oil recovery and injectivity during CO2 flooding. Horizontal core flooding experiments under WAG mode was performed at pore pressures of 3,200 psi and 3,800 psi.
The experimental results indicate that tertiary oil recovery was influenced significantly by different CO2 injection modes and the direction of displacement. 18.4% and 26.74% of original oil in cores were recovered for horizontal and vertical experiments of continuous CO2 injection modes, respectively. In horizontal WAG experiments with different pore pressures, higher oil recovery was observed at a pore pressure of 3,800 psi compared to 3,200 psi. The marginal increase in incremental oil recovery indicates that pressure increase beyond 3,200 psi will not have a significant impact. The injectivity of different CO2 injection modes is reported in this paper.
Measurements of Volumetric Phase Behavior of Mixtures of n-decane and CO2 at High Pressures and High Temperatures
Authors: Rahman Saifur , Kandil Mohamed E. , Al-Saifi Nayef , Sultan Abdullah S. 
Published: June 2015

Abstract
The use of CO2 as an enhanced oil recovery agent is ever increasing as CO2 is becoming widely used for heavier oil production. The environmental burdens of CO2 also encourage that it should be disposed of in a way that those liabilities are minimized. Hence there is a need for understanding the phase behavior of Hydrocarbon-CO2 systems and mechanism by which the hydrocarbon rich phase is displaced. Accurate data on phase behavior of mixtures containing hydrocarbons and CO2 will not only help in oil recovery and production but also will help in designing infrastructure for transportation and downstream separation.
Solubility of CO2 in hydrocarbons at low and moderate pressures is pretty good. This phenomenon reduces the density of the mixture and volume swelling is observed. At high pressure range there is a dramatic increase in the density of CO2 with pressure, which can produce a complete miscibility. In some complex mixtures of hydrocarbon and CO2 a second liquid CO2-rich phase can also exist.
Development of experimental methods and technique for measurements of volumetric properties for binary mixtures of CO2+ n-decane will be discussed. The phase behavior properties measured include isothermal compressibility, mass density, bubble points at temperatures from (313 to 410) K and pressures up to 76 MPa (11000 psi). Our data are compared with the predictions from equation of state (EOS) models commonly used in software simulators. The accuracy of experimental data and challenges in development of the experimental technique will also be discussed.
Successful Installation of Multistage Choke Valve Technology in Water Flowlines to Reduce High Pressure Drop across Choke Valves
Authors: Al Saeed Abdullah J. , Al Mousa Salah A. , Al Ajmi Mohammed A. , O'Donnell Martin 
Published: June 2015

Abstract
Reasons for internal and external valve damage are varied in the industry. Valve damage can occur due to irregular preventive maintenance, sand erosion, internal and external corrosion, improper materials selection, and/or due to operating the valve outside of its operating pressure and temperature ranges1. This paper will focus only on valve cavitation related damage, which happens on water choke valves.
The main purpose of this paper is to demonstrate a trial installation of multistage choke valve technology in water lines that reduces high pressure drops across water injection choke valves. The trial test was conducted on two single-stage choke valves installed upstream of two water injection wellheads, which were completed in two different reservoirs. The selected single-stage choke valves were experiencing high noise and vibration levels where operators could barely meet the required water injection rate for each well.
Different surface mitigation measures were evaluated to overcome this serious issue prior to conducting the trial installation of the multistage chokes. The field water injection system was studied from the water injection plant (WIP) where the water injection centrifugal pump (3000 psig) is located, through the water lines, fittings and valves all the way to the water injection wellheads. Results from the trial test show that implementing multistage choke valve technology can prevent high noise and vibration levels and allow the target water injection rate per well to be met.
An Integrated Approach for Downhole Leak Detection
Authors: Al-Hussain Ali Musa , Hossain M. Enamul , Abdulraheem Abdulazeez , Gajbhiye Rahul 
Published: June 2015

Abstract
Effective well integrity practices ensure the protection of people, facilities and the environment from the risk of uncontrolled release of formation fluids throughout the life cycle of a well, so petroleum engineers are always required to ensure well integrity. Part of well integrity is to make sure downhole equipment and barriers are in excellent condition. Identifying the downhole leak source of pressure communication between tubingcasing and casing-casing annuli in any well is a huge challenge for petroleum engineers. Detecting any leak at the early stage is an important key to well integrity management. Two objectives were set in this paper as follows: The first objective is to develop a method that can detect downhole leaks by utilizing only rigless data based on full interpretation and evaluation of different logs in the field: temperature, noise, and corrosion log in different scenarios. The first scenario is shut-in condition while the second scenario is in flowing condition. The flowing condition will be either after bleeding off Tubing-Casing-Annulus or Casing-Casing-Annulus. This approach was implemented in a specific operation order to ensure job success. Also, the corrosion log was run to evaluate the condition of tubing and casing separately. The second objective of this study is to compare rigless approach results with the conventional rig approach for downhole leak detection, which will be completed by statistically analyzing corrosion, temperature, and noise surveys. Moreover, guidelines were set in each step of these surveys to confirm leak occurrence. This objective was achieved through developing a method and program for leak detection. Based on the conducted temperature, noise, and corrosion surveys, the integrated approach identified the leakage zones through the developed module in this report. The obtained results from the rigless approach were almost similar to the rig approach. The only difference between both approaches is that the developed method is more accurate, compared to the rig approach, since it can identify any corrosion or leak depth, while the rig approach will identify only leak zones. The paper will discuss in details the development of this method and its successful implementation in a few selected offshore wells in the same field of the Arabian Gulf.
Assessment of Water Injection-Related Scale Risks for an Onshore Carbonate Oilfield Incremental Development Project in Central Arabia
Authors: Osode P. I. , Almubarak T. A. , Bataweel M. A. , Al-Faifi M. G. , Al-Khaldi M. H. 
Published: June 2015

Abstract
Water flooding has been widely used in the industry as a secondary recovery technique to improve recovery from oil reservoirs. One of the major operational challenges is addressing the compatibility between injected water and formation water in order to proactively lower the probable risk of scale formation near wellbore. A thorough investigation was conducted to evaluate the probability of scale formation and identify the effective mitigation options for a Central Arabian incremental development project.
A holistic approach was implemented at this study to achieve the objective through reviewing analogue reservoirs, running numerical predictions of scale tendency, carrying out laboratory experiments to evaluate the compatibility of the formation water with the injected mix water and conducting in-situ coreflood experiments to quantify the potential risk of formation damage.
This study identified an inherently high calcium sulfate scale risk associated with the planned seawater injection in the new reservoir development and within the surface production fluid process facilities. Appropriate scale mitigation options including the potential impact of an injection seawater sulfate removal process facility will be discussed in this paper.
Analysis of High Temperature Sour Gas Wells to Mitigate Corrosion and Scale Formation
Authors: Ramachandran Sunder , Gupta Anuj , Al-Muntasheri Ghaithan , Leal Jairo , Syafil Irfan 
Published: June 2015

Abstract
In this paper a review of the thermodynamics of gas/condensate and water systems with hydrogen sulfide and water/hydrocarbon wetting and its influence on corrosion is presented.
Compositional analysis is used to provide information on the variation of different material streams and composition as a function of depth. Although on the surface, the liquid stream of a well can predominately consists of hydrocarbon, the liquid stream downhole can have a very different composition. The variation of liquid composition, pressure, temperature, ionic composition and flow regime can have interesting implications on sour corrosion and scale formation.
Calculations on scaling conditions and thermodynamic conditions that cause corrosion are done on a well under bottom hole and well head conditions. Iron sulfide films that are formed during high temperature CO2/H2S corrosion of carbon steel and often layered structures of scale are formed where the composition of scale varies with depth. The calculations provide guidance on the types of iron sulfide and iron oxyhydride scales that may form.
Compositional Analysis and Treatment of Oilfield Scales
Authors: El Hajj Hicham , Pal Omprakash , Zoghbi Bilal 
Published: June 2015

Abstract
Scale formation in the wellbore and pipelines during upstream processes can result in production disruptions and declines in revenue. Hence, treatment and removal of oilfield scales are important for avoiding production depreciation. Scale varies in chemical composition, being composed of layers of scale adhering to the inside of tubing and deposited during the well life cycle. Identifying the location and composition of scale deposits is the first step in designing a cost-effective remediation program. Scale removal could be mechanical or chemical. Scale removal techniques should be quick, non-damaging to the wellbore, tubing, or formation environment, and effective at preventing reprecipitation. There have been many significant advances in scale control and remediation in recent years. Improvements in placement technology, reservoir chemistry, and intelligent fluids provide more cost-effective options for chemical scale inhibition or removal in downhole tools. The purpose of the present study was to analyze scale composition and then develop and recommend a solution to effectively remove specific oilfield scale from downhole tools. In this study, scale samples were collected from downhole tools and compositional analysis conducted to characterize both crystalline and non-crystalline compounds. Composition of scale samples was determined by X-ray diffraction (XRD), X-ray fluorescence (XRF), and acid solubility for more accurate analysis. XRD and XRF results showed that the scale composition was mostly carbonate. Based on the scale composition, an acid-free carbonate scale dissolver was evaluated, and the results are presented in this paper.
Comparative Analysis of Feature Selection-Based Machine Learning Techniques in Reservoir Characterization
Authors: Akande Kabiru O. , Olatunji Sunday O. , Owolabi Taoreed O. , AbdulRaheem AbdulAzeez 
Published: June 2015

Abstract
Comparative study and analysis of the generalization performance and predictive capability of machine learning (ML) techniques in reservoir characterization and modeling is presented in this work by utilizing two distinct Oil well data sets. The performances of the ML techniques (artificial neural network (ANN) and support vector regression (SVR)) have been boosted by proposing a correlation-based feature selection approach which employs fewer datasets resulting in less computing time and processing power. Predictive accuracy of both ML techniques in permeability prediction has been improved as a result of the feature-selection approach. Furthermore, ANN shows superior performance in case of large dataset while SVR shows better performance in case of small dataset. The results of this work provide excellent insight and guidance to practitioners in improving ML performance and determining the most appropriate technique in cases of small and large datasets.
A Methodology for Identifying & Quantifying Uncertainties (Seismic to First Phase Field Development) in Reservoir Simulation: Case Study of Two Fields in Saudi Arabia
Authors: Moriwawon Babatunde , Al-Turki Ali , Al-Shawaf Ali , Radhey Bansal 
Published: June 2015

Abstract
Understanding and management of subsurface uncertainties has become increasingly important for oil and gas companies to optimize reserve portfolios, make better field development decisions and improve day-to-day technical operations such as well planning. In this paper, the authors developed models, workflows and methodologies for multiple development scenarios that span the range of uncertainties for all stages of reservoir description and simulation for two fields (Field A and Field B) in Saudi Arabia. These processes are based on responses to uncertainty parameters in order to capture and quantify uncertainties. Uncertainty quantification for the two reservoirs was performed using experimental design (ED) approach taking into account seismic interpretation, geological uncertainty, and dynamic data. ED is an intelligent way of sampling parameter space by selecting combination of predefined variables to minimize the number of "experiments" to characterize the behaviour of a system, and to limit the number of models to be run. As a result, robust and responsive reservoir models were constructed to predict the field performance as well as to evaluate various future development strategies alongside better risk-assessments.
Step Change in Hydraulic Fracturing Methodology by Analyzing Clastic Gas Reservoir Field Experience to Achieve Production Enhancement
Authors: Al-Ali Ammar H. , Islam Ashraf 
Published: June 2015

Abstract
The clastic non-associated gas reservoirs are encountered in one of the Saudi Arabian oilfields. There is a wide variation in permeability in this Devonian age formation, varying from tight rocks with 0.1 md or less to more than few Darcie's in highly unconsolidated sandstones. While the prolific areas are easily producible at sustained high gas rates by conventional drilling and using sand control completion mechanisms, the relatively tighter areas require hydraulic fracturing to sustain commercial flow rate.
During the last 10 years, the field A focused on exploiting gas reservoirs is being developed with vertical or S-shaped wells, and completed using a monobore tubular assembly. Proppant fracturing treatments are routinely conducted in multiple stages along the vertical wellbore. Fracture treatment parameters are adjusted over time by the introduction of different fracture fluids to enhance stability and avoid premature screen out. Proppant flow back measures were taken with the use of resin-coated proppants. A large database was developed on stimulation treatments and results that allowed conducting a detailed analysis to understand the behavior and effect of hydraulic fracturing trends on the reservoir performance to optimize the design parameters and further increase reservoir potential.
This paper documents the analysis of the pre- and post-fracture treatment data, production analysis and thorough evaluation of petrophysical and geomechanical measurements from this massive database of 10-year long operational period. This study shows that there is a room to improve fracturing treatments and fluid chemistry and recommends a step change in the well stimulation strategy by modifying some existing technologies and also applying novel technologies that have been carefully studied and approved using laboratory and field trial testing. The results from the application of this new strategy are presented in the paper using actual examples.