bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Oil Recovery Using Nanoparticles
Authors: Ogolo N. A. , Olafuyi O. A. , Onyekonwu M. O. 
Published: April 2012

Abstract
Nanoparticles have been speculated as good in-situ agents for solving reservoir engineering problems. Some selected types of nanoparticles that are likely to be used include oxides of Aluminium, Zinc, Magnesium, Iron, Zirconium, Nickel, Tin and Silicon. It is therefore imperative to find out the effect of these nanoparticle oxides on oil recovery since this is the primary objective of the oil industry. These nanoparticles were used to conduct EOR experiments under surface conditions. Distilled water, brine, ethanol and diesel were used as the dispersing media for the nanoparticles. Two sets of experiments were conducted. The first involved displacing the injected oil with the nanofluids. In the second case, the sands were soaked in nanofluids for 60 days before oil was injected into the system and displaced with low salinity brine. Generally, using nanofluids to displace injected oil produced a better result.
Results obtained from the experiments indicate that Aluminium oxide and Silicon oxide are good agents for EOR. Aluminium oxide nanoparticle is good for oil recovery when used with distilled water and brine as dispersing agents. For the use of ethanol, Silane treated Silicon oxide gave the highest recovery in all the conducted experiments while hydrophobic Silicon oxide in ethanol also yielded good results. Aluminium oxide reduces oil viscosity while Silicon oxide changes rock wettability in addition to reduction of interfacial tension between oil and water caused by the presence of ethanol. For the use of diesel as a nanoparticle dispersing fluid, because diesel and crude oil are miscible, the actual crude oil recovery cannot be determined but the overall result with Aluminium, Nickel and Iron oxides appears good. Magnesium oxide and Zinc oxide dispersed in distilled water and brine cause permeability problems. Generally, distilled water lowers oil recovery. This emphasizes the significant role a fluid plays as a nanoparticle dispersing agent in the formation because it can contribute positively or negatively in oil recovery apart from the effect of the nanoparticles.
A New, Low Corrosive Fluid to Stimulate Wells with Carbon Steel Tubular and Internals
Authors: Nasr-El-Din H. A. , de Wolf C. A. , Bouwman A. , Bang E. R. , Naylor E. , Alex A. 
Published: April 2012

Abstract
For many reasons acidizing treatments represent a real challenge to the oil and gas industry. On one side acidizing can significantly improve the productivity of the well, but on the other side the intrinsic corrosive character of the acids form a severe threat to the well's integrity. Therefore traditional acidizing treatments with fluids involve significant loadings of corrosion inhibitors and corrosion inhibitor intensifiers to help mitigate the corrosion. However, the additives can cause their own damage to the formation, reduce overall effectiveness of the acidizing fluid, and come with significant additional costs to the overall acidizing program.
Recently studies with a new environmentally friendly stimulation fluid, glutamic acid diacetic acid (GLDA), were presented for both carbonate and sandstone reservoirs. The studies have shown that GLDA can dissolve calcite & dolomite, does not destabilize clays particles, and can significantly improve permeability in both carbonate and sandstone formations across wide field conditions. In the present paper the corrosion rate of GLDA is compared with other chelates and simple organic acids that are used for carbonate dissolution, such as hydroxyethylethylenediaminetriacetic acid (HEDTA), acetic, citric and formic acid. All corrosion tests were conducted at high temperature and pressure and extended for up to 6 hour at temperature and pressure.
The results show that GLDA at 20 wt% has the least impact on low carbon steel, in comparison to the other stimulation fluids examined in this study. A very minimal amount of corrosion inhibitor loading was needed to keep the corrosion rate below the acceptable rate for GLDA, even at elevated temperatures or in the presence of corrosive gases like H2S and CO2. On more corrosion resistant Cr-based metals, like Cr-13 and duplex, the corrosion rate of GLDA is far below the acceptable limit with no corrosion inhibition even at 300°F. Based on the results, GLDA solutions can be used to stimulate carbonate and sandstone wells completed with various types of metallurgies with no or very minimal amount of corrosion inhibitors and effectively maintain the integrity of the tubular & internals.
Production Enhancement Using a Multiphase Helico-Axial Pump in a Remote Hilly-Terrain Oil Field in Saudi Arabia
Authors: Samsudin Zulkifli B. , Ajmi Shaleh M. , Qudaihy Dia S. , Dossary Faisal M. , Gharaibeh Alaa , Tvedt Jostein 
Published: April 2012

Abstract
Some of the wells in the southern part of a remote field in Saudi Aramco are either producing intermittently or ceasing to flow against the high trunk line pressure. Saudi Aramco had considered various options along with horizontal thrust boring direct drilling under the sand dunes to reduce this high back pressure. A helico-axial multiphase pumping (MPP) technology was selected for the trial test in this field since in 2005 the horizontal thrust boring technology was limited to distance up to 2 km. In addition, the multiphase pump provides the flexibility such as reducing the back pressure and particularly, the helico-axial technology has a wider operating envelope as some wells will be weaker in the long run.
Saudi Aramco has successfully re-commissioned the MPP in January 2011, and it was trial tested for a nine month period at the remote area with three dead wells and two marginal flowing wells. A total of 7,000 to 8,000 barrel oil per day incremental production was realized by lowering the back pressure on these wells using the MPP.
This paper describes the testing, field operational experience and recommended improvement of a rotodynamic (helico-axial) MPP system at a remote, hilly terrain onshore oil field in Saudi Arabia. This paper is a sequent to SPE-117462 paper, Deployment of Rotodynamic Multiphase Pump in a Remote Hilly-Terrain Oil Field in Saudi Arabia," presented at the 2008 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE.
Application of Latest Generation Inflow Control Devices in Non-Horizontal Wells in India, Case Study
Authors: McKenzie Tim , Wenk Andrew , Chavan Chetan , Kumar Sanjay , Khan Parvez , Garcia Gonzalo 
Published: April 2012

Abstract
Bhagyam is the second largest oilfield discovered to date in the Barmer Basin, India with more than 400mmb of viscous, waxy crude in place. This paper describes the evaluation, design and selection process for the use of the latest generation ICD in non-horizontal wells.
Sandface completions comprise sand screens coupled with an ICD. Inflow control was highly desirable due to the oil viscosity variation, high permeability, heterogeneity and adverse mobility ratio and the fact the completions could not be easily accessed below a PCP. Oil viscosity ranges from 20 to 250cp varying with depth. The variation in reservoir thickness, produced fluid viscosity and well productivity required a field adjustable pressure drop capability in the ICD. The ICD had to perform at high viscosity and needed to be tolerant to wax and sand production. The operator's experience in nearby fields observed the benefits of ICDs for providing efficient sandface cleanup in horizontal wells. It was vital to model this system accurately however there were significant challenges as no previous examples of using these devices in non-horizontal wells could be found and the ICD completion had not been modeled in a dynamic simulator for this scale of field development.
A dynamic simulation model which included the ICD completion was used to evaluate various completion options. A significant amount of work was performed to ensure the ICD was accurately modeled in the simulator. The simulations showed a long term benefit from using the ICD. To date 22 production wells have been completed with the ICD screen systems.
This is one of the first applications of the latest generation ICD in non-horizontal wells particularly on a full field scale. It is also a case study of modeling the ICD completion with a dynamic simulator.
Precise Approach to Isolate Fractured Water Bearing Lower Zone in Complex Saudi Arabian Gas Well by Placing Ceramic Proppant and Cement in Restricted Depth Utilizing HPCT to Withstand High Bottom-hole Pressure during Fracturing Treatment in the Upper Zone: A Case History
Authors: Malik Ataur R. , Duarte Jorge E. , Kulaib Hamad F. , Atwi Mohammed A. , Eduardo Vejarano R. , Riefky Abdurrahman 
Published: April 2012

Abstract
Success of Multi-Stage Fracture treatment in deviated cased hole completion largely depends on isolation mechanism of the previously created fractures in the lower zones under the presence of complex reservoir characteristics and wellbore conditions. The lower zones need to be temporarily or permanently isolated utilizing cast iron, composite or sand plugs capped with cement that must maintain integrity and be able to tolerate high differential pressure across the plug during hydraulically fracturing the upper zones.
The subject paper is a review of the design philosophy, planning, laboratory testing, execution and results of successful isolation of lower complex zone with high stress, high pressure and high temperature (BHST = 315 deg F) where proppant fracturing treatment prematurely screened out exceeding maximum bottomhole treating pressure limit of the completion of a gas well in Saudi Arabia. The high differential pressure (greater than 10000 psi) requirement of the isolation plug eliminated the mechanical bridge plug options as a result of uncertainty of the liner condition from unprecedented high screenout pressure and dubious cement quality behind the pipe. The only viable option that remained was a customized plug made up of ceramic proppant capped with 100 mesh sand and high temperature cement. The objective of ceramic proppant from plug back depth to top of perforated interval of the lower zone and capped with 100 mesh sand was to work as base for cement and controlling leak-off of cement into the lower fractured zone. The short distance between the perforated intervals of lower and upper zones, maintaining balanced condition during placement of proppant and cement plugs and controlling leak-off of cement across the fractured lower zone required high level of scrutiny in the selection of proppant type, designing cement properties in the laboratory, quality control and ultimately placement of the slurries utilizing high pressure coiled tubing (HPCT). The real time monitoring of temperature and pressure data from permanent downhole gauges enabled to maintain balanced to slightly overbalanced condition that significantly contributed the set a plug in target depth with desired strength. The plug was successfully pressure tested to a bottomhole pressure of 15000 psi. The plug maintained it's integrity during the DataFrac performed in the upper zone after perforation. The successful application of this isolation method enabled two additional fracture treatments in layers at the shallower depths of the same well.
Molecular Design Synthesis and Simulation on a Novel Gemini Surfactant for EOR From Low Permeability Reservoirs
Authors: Wei Heng 
Published: April 2012

Abstract
High injection pressure and the imbalance between water injection and oil production are two of the difficulties in developing low permeability oil reservoirs. Injecting gemini surfactants is a promising technique to overcome the difficulties to enhance oil recovery from low permeability oil reservoirs. Based on fractal analyses, a novel gemini surfactant is designed, and its possible synthesis route is suggested.
The novel gemini surfactant is put into computer simulation. The results show that the novel gemini surfactant has better effects on washing oil than conventional gemini surfactants. The novel gemini surfactant has a great potential in enhancing oil recovery.
The fractal dimension of the spacer group of the novel gemini surfactant is close to the fractal dimension of the microstructure of the reservoirs. This is the key point in designing the novel gemini surfactant.
The fractal analyses of the key molecular structures help design more exact and efficient oilfield chemicals. Once the novel gemini surfactant is put into practical use, it will have active effects on both oil development and refinery industries.
Comparisons and Contrasts of Shale Gas and Tight Gas Developments, North American Experience and Trends
Authors: Kennedy Robert L. , Knecht William N. , Georgi Daniel T. 
Published: April 2012

Abstract
All Shale Gas reservoirs are not the same. There are no typical Tight Gas reservoirs. These two statements can be found numerous times in the literature on shale gas and tight gas reservoirs. The one common aspect of developing these unconventional resources is that wells in both must be ‘hydraulically fractured’ in order to produce commercial amounts of gas. Operator challenges and objectives to be accomplished during each phase of the Asset Life Cycle (Exploration, Appraisal, Development, Production, and Rejuvenation) of both shale gas and tight gas are similar. Drilling, well design, completion methods and hydraulic fracturing are somewhat similar; but formation evaluation, reservoir analysis, and some of the production techniques are quite different.
Much of the experience in shale and tight gas has been developed in the US and in Canada, to a lesser extent; and most of the technologies that have been developed by operators and service companies are transferable to other parts of the world. However, the infrastructure, including equipment and service company availability, governmental regulations, logistics, processing, environmental considerations, and pricing are not the same as in the US. This may impact the rate of the technology transfer as well as the selection of some of the technology. This paper is focused on operations challenges, technologies, and experience associated with shale and tight gas projects. It is likely that environmental concerns and the drive to reduce development costs of tight and shale gas reservoirs will drive new approaches to the development of these reservoirs in China, Latin America, Middle East, North Africa, and other parts of the world.
Powering Through a Lateral Junction for ERC Wells – Is It Really a Step Too Far?
Authors: Bouldin Brett , Verma Chandresh , Dyer Steve , Singh Parvesh , Oliveira Thales 
Published: April 2012

Abstract
Saudi Aramco and Schlumberger recently embarked on a phased field implementation to build "Extreme Reservoir Contact" wells (ERC). The paper presents the experiences on a recent trial well that deployed an intelligent completion through a multilateral junction in an open hole lateral. We present the conceptual design, tools, techniques and learnings associated with this test.
The application of this technology lies in the construction of ERC well infrastructure to actively control segmented lateral inflow and improve reservoir sweep. A key stumbling block in realizing this vision is to branch the lateral junction with power and communication.
The well trial demonstrated the ability to deploy a completion assembly with umbilical to the bottom of an openhole lateral.
The major design and operational steps discussed herein include:
Installing and cementing an umbilical behind casing Milling the junction window without causing damage to the umbilical Drilling, clean out and fluids used in the lateral to reduce drag Dressing and drifting of the junction Installation and retrieval of a dummy lateral completion assembly with umbilical through a window and without rotation
"Extreme Reservoir Contact" is one of the key technologies in Saudi Aramco's vision of increasing recovery factors from their fields. They differ from the current "Maximum Reservoir Contact" (MRC) practice in further increasing reservoir contact, while also increasing well compartmentalization with individual compartment control. Laterals can be instrumented with enhanced sensor systems to efficiently monitor hydrocarbon reserve drainage.
The reliable deployment of remote control valves and sensing devices through milled junction windows is a key step in realizing this vision. The full benefit in drilling these downhole well structures demands pro-active control of reservoir fluid production and the mitigation of early water or gas breakthrough. Bringing emerging new intelligent completion technology into the laterals will significantly impact the industry in this regard.
Exploring and Evaluating Eastern Hemisphere Proppants in Fracturing Applications
Authors: Kothamasu Ramya , Das Prasanta , Karadkar Prasad 
Published: April 2012

Abstract
As the market for fracture stimulation emerges internationally, selecting the proper proppant is essential. Comparing data from different proppants can aid proper selection for particular reservoir applications. Correlations between the test data can be used to forecast the proppant behavior inside the formation.
API and ISO standards were used for qualifying tests, such as specific gravity (SG), bulk density, acid solubility, turbidity, sphericity, roundness, sieve analysis, crush strength, and long-term fracture conductivity. The significance of each test is discussed, the results are compared, and correlations are developed. Each test has been weighted, and a scoring index is provided to demonstrate how the quality of proppant should be considered to help select the optimum proppant.
This work provides insight into proppants manufactured in different regions in the eastern hemisphere. The characterization of different proppants from the tests performed reflects how different local sourcing options can impact proppant quality. The scoring index can be used as a quick guide for the preferred proppant selection for a specific well stimulation.
How Advances in Technology can Help Safely Abandon Off-Shore Subsea Wells
Authors: Segura Richard , Haq Mohammed A. 
Published: April 2012

Abstract
At some point, an oil or gas well inevitably shifts from asset to liability, whether the result of reaching its economic limit, sustaining irreparable damage or being a disposable exploratory well. At the end of its life cycle, a well must be plugged and abandoned (P&A); while adhering to regulatory and environmental standards, its supporting infrastructure must be carefully dismantled to ensure that it poses no safety or environmental threats and any useable components salvaged to help defray costs. In addition to creating significant safety and environmental hazards, failure to properly abandon a well can lead to a noncompliant status with regulatory agencies and undermine an operator's image. Despite its multiple liabilities, abandonment offers no real return on investment (ROI), underscoring the importance of minimizing cost while still ensuring a safe and regulatory compliant operation. One of the main challenges is to retrieve the wellhead without damage so that it can be used again.
Clearly wells in onshore or shallow water offshore environments present little difficulty in accessing the wellhead and carrying out the required P&A operations. However the most challenging wells to P&A are deepwater wells where the wellhead is located on the ocean floor often at considerable depth so that physical access to it is infinitely more challenging. In this subsea environment there exist two different approaches to the problems associated with well abandoned and wellhead recovery. These involve internal cutting of the surface and conductor casings combined with either internal or external latching of the wellhead.
In this paper the authors will review these two different approaches, comparing their viability and describe in detail the external latching system which offers some distinct advantages in the P&A process. They will go on to provide some detailed case studies which illustrate its’ successful use in various deepwater offshore operations.
State-of-the-art Openhole Shale Gas Logging
Authors: Franquet Javier A. , Bratovich Matt W. , Glass Richard D. 
Published: April 2012

Abstract
Faced with increasing field maturity and production decline from conventional gas reservoirs, oil companies are shifting their focus and pursuing new alternatives; one of them being the development of shale and gas plays. To be economically viable, these low-permeability formations require fracture stimulation. Interval selection within shale reservoirs for hydraulic fracturing or horizontal laterals are based on several variables: sufficient organic matter or total organic carbon (TOC) and favorable hydraulic fracturing stimulation. The presence and extent of the natural fracture system can also influence the performance of a shale reservoir; therefore, natural fractures should be characterized within the shale formation not only from wireline or LWD borehole images logs but also from cross-dipole deep shear wave imaging which can illuminate fractures up to 60 ft away that do not intersect the well. To assess these aspects, a mineralogical, structural, and geomechanical characterization of the shale formation should be conducted. The mineralogical characterization and TOC quantifications mainly rely on a pulsed neutron spectroscopy and nuclear magnetic resonance (NMR) logs. The processing of capture and inelastic gamma ray spectra obtained from the pulsed neutron tool quantifies the formation's basic elemental composition, including silicon, calcium, aluminum, iron, sulfur, magnesium, and carbon. Geomechanical characterization is based on acoustic and density log responses. Variation in the reservoir mineralogy and TOC content affect the rock mechanics properties. Stress vs. strain curves can be derived from a micro-mechanical model of the rock which enable correlations between dynamic (obtained from acoustic logs) and static elastic properties (obtained from triaxial compression testing on core samples). Additionally, the azimuthal and transverse shear wave anisotropies are processed from cross-dipole acoustic logs to characterize the vertical and horizontal rock stiffness. This anisotropic characterization of the rock enables the evaluation of the fracture gradient and stress contrast between the target formation and the overlying and underlying formations. The paper focuses on the interaction between mineralogy, organic content and geomechanical analyses in shale gas reservoir evaluation.