bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Reliability of Surface Safety Valves by Upgradation with Self Contained Hydraulic Retrofit for Sour Services
Authors: Al-Azmi Falah , Parikh Chirag A. 
Published: December 2013

Abstract
The Surface Safety Valves (SSVs) installed downstream of the well head were put in lock open condition for many of the flowing ESP wells at West Kuwait field of Kuwait Oil Company. This was done to prevent damage to ESPs (installed down hole) due to frequent faulty trips of these valves. In such operational scenario, the SSV was not performing its normal function for which it is designed for, that is, to act as a safety barrier against abnormal flow conditions. The SSV malfunction was attributed to contact of hydraulic oil with the flowing sour crude oil and resulting contamination from the suspended solids, asphaltene and wax present in the crude. A pilot trial was conducted to upgrade these SSVs with Self-contained hydraulic control system and to evaluate functioning of this control system in providing adequate hydraulic actuation control to the already installed surface safety valves. This up gradation of flow powered SSVs (actuators) with self-contained hydraulic control system provides a low cost solution for improving performance and reliability these SSVs without any need of replacing complete surface safety valve. It is possible to achieve almost 100% reliable performance by installing such retrofit.
Successful Asphaltene Cleanout Field Trial in on-shore Abu Dhabi Oil Fields
Authors: Misra Sanjay , Abdallah Dalia , Nuimi Saber 
Published: December 2013

Abstract
Two of the prominent on-shore fields in Abu Dhabi are facing asphaltene deposition in a number of their oil producing wells. Several studies were carried out to understand the reasons for asphaltene unstability in the crude in both fields to help develop the appropriate mitigation strategies. A summary of the findings will be presented in this paper, however, the focus will be on the efforts undertaken to improve the current asphaltene clean-out formulations that are being used in the field. These formulations are composed of a dispersant chemical mixed with diesel as a solvent in 20:80 ratio and are pumped with the use of a Coil Tubing Unit (CTU) in tandem with jet blaster. However, the success rate reported for such clean-up jobs was 40% on average. Hence lab testing was carried out on a number of new dispersants and other potential solvents to improve the efficiency of the clean-up operations. After testing a combination of 8 commercially available dispersants with 3 solvents: Diesel, light gasoline oil (LGO), heavy aromatic naphtha (HAN), it was clear that a mixture of HAN with 3 particular dispersants in a 90:10 ratio were many times more efficient than the currently used formulations. These top lab ranked formulations were then field trialed in 7 wells by bullheading only, soaking overnight and running a gauge cutter to prove accessibility and success of the clean-up job. The wells were found to be perfectly cleaned with 25% reduction in the chemical requirement and a major saving in terms of avoiding the use of CTU for the clean-up operation. Implementation of new formulations would affect multimillion dollar cost saving. The savings increase many fold when opportunity costs against the previous unsuccessful jobs is taken into account. Besides, valuable resources like CTU can be gainfully deployed elsewhere. Results of this field trial will have larger implications for ADCO in the future as the number for asphaltene affected wells is rising as a result of field maturity and implementation of Enhanced Oil Recovery (EOR) and Artificial Lift (AL).
Memory Pulsed Neutron Logging - Avoiding Production Shutdown Losses Caused by In-field Logistical Constraints
Authors: Bilbeisi Jawdat M. , Chaker Hicham Abu 
Published: December 2013

Abstract
Proactive reservoir management is key to extending the maximum sustainable production plateau and achieving high recovery factors from any asset. A crucial parameter to monitor over time is reservoir fluid saturation, which is normally addressed with Time-lapse Pulsed Neutron Log data acquisition campaigns. The increasing complexity of secondary and tertiary oil recovery schemes (miscible gas injection) has created an even greater dependency on saturation monitoring tools to better delineate fluid movement within the reservoir.
The offshore fields in the UAE are quite mature, with a large number of wells and all associated infrastructure. Reservoir saturation logging campaigns are made increasingly difficult due to resource limitations - winch boats for equipment movement, slickline units for Down Hole Safety Valve retrieval and Tubing checks as well as offshore living accommodation limitations are major factors, any of which can cause the halt of a rigless logging campaign.
Further to the above logistics factors, the production losses associated with such a campaign due to well shutdowns caused by logging units on WHT compound the problem, as they tend to interfere with production targets, further reducing the number of wells available for monitoring.
A new Memory Pulsed Neutron Logging service has successfully been introduced into the UAE, which avoids these field logistics issues and minimizes production losses caused by saturation data acquisition, without negatively affecting data quality. The successful implementation of the first worldwide Coiled tubing conveyed Memory Pulsed Neutron logging service has further saved the operator time and money in terms of operational efficiency. This paper is designed to highlight all aspects in terms of operations, data quality and positive impact on hydrocarbon production associated with rigless logging operations. Case histories will be used to illustrate the gains. Potential future developments and applications will also be discussed.
Asphaltene Precipitation from Crude Oils : How to Predict it and to Anticipate Treatment?
Authors: Passade-Boupat Nicolas , Zhou Honggang , Rondon-Gonzalez Marianna 
Published: December 2013

Abstract
The prediction of asphaltene precipitation is an important topic in petroleum industry. Reliable evaluation of the asphaltene stability requires representative samples and measurement using special high pressure equipment. Moreover, development project may involve many reservoirs with many different fluids. Even inside of a connected reservoir, the quality of the oil and the asphaltene can vary through a large scale and the investigation of each fluid in the representative conditions become very expensive and often impossible.
Many fast screening methods have been proposed so far. The De Boer’s diagram is one of the most useful methods. However, it takes into account only the properties of the hydrocarbon phase without any investigation on the asphaltene fraction : this method gives always pessimistic prediction of the risk of asphaltene precipitation. Other methods, colloidal instability index for example, are not consistent enough to be used for flow assurance issue.
Based on some relevant solubility properties of the asphaltene fractions, a new and easy way for screening asphaltene instability is proposed. Using PVT properties of the live oil and an easy asphaltene characterization procedure, this method allow limiting advanced investigation only to fluids which present a real risk of precipitation. The asphaltene characterization can be performed on dead oil samples.
If a precipitation risk is stated, additional tests, performed on pressurized representative samples or taking into account reorganization of asphaltenes from different fluids, will help to define the severity of the risk. For mitigation, a test set-up has been developed: it allows evaluating the efficiency of chemical additives to prevent plugging under flow conditions of fluids above the asphaltene precipitation threshold. Depending on the crude oil, the severity of the precipitation conditions, and the nature of the additive, the blocking of the capillary tube can be delayed or prevented.
Type Curves for Pressure Transient Analysis of Horizontal Wells in Shale Gas Reservoirs
Authors: Lee Sung Jun , Kim Tae Hong , Lee Kun Sang 
Published: December 2013

Abstract
Shale gas has been recently emerged as a potentially enormous resource. Even though significant progresses have been made in the past few years, there appears to be a lack of information regarding the characterization of shale gas formations. A major purpose of the study is to demonstrate how this issue may be addressed by pressure transient analysis for horizontal wells in shale gas reservoirs. Extensive numerical simulations were conducted to model transient pressure behavior of a horizontal well and apply the results to well test analysis in shale gas reservoirs. For the simulation of realistic reservoir flow processes, the model incorporates a number of important formation properties and nonlinear processes in shale gas reservoirs including effects of well vertical location and length, dual porosity/dual permeability model, Klinkenberg effect, non-Darcy flow behavior, and adsorption/desorption under reservoir flow condition in addition to skin effect. Results from numerical simulations for nonlinear gas flow provided various type curves in terms of dimensionless pseudopressure and time for transient pressure responses in horizontal production wells. Results from type-curve matching for synthetic pressure data in shale gas reservoirs demonstrate that the conventional analysis approach may still be applicable for analysis of shale gas reservoirs. The results were shown to be a useful tool for the quantitative analysis on the transient gas flow behavior and determination of formation properties.
Structural Controls of Fracture Corridors in Some Middle East Fields
Authors: Ozkaya Sait I. 
Published: December 2013

Abstract
Two main structural types can be distinguished in the oil fields of the Middle East. (i) Fields transected by regional strike slip faults (type I structures). (ii) Fields with local faults that are associated with and confined to anticlinal structures (type II structures). Type II structures are either (i) growth folds mostly bound by deep seated faults which were reactivated under transpression or (ii) product of structural inversion, during Late Cretaceous and Late Tertiary major tectonic events. The reactivated faults have usually very small lateral displacement and the structures have very gentle dips.
The characteristic fault fracture patterns of type II anticlines in the Middle East have two diagnostic aspects: (i) faults and fracture corridors have uniform strike oblique to anticlinal axis and (ii) they disappear away from the structural highs towards franks and away. These two characteristic aspects can be explained only by superposition of regional stress and local tension related to structural bending.
Stress superposition not only explains the diagnostic faults and fracture patterns of type II structures, but also account for several details such as higher degree of fracturing in doubly plunging structures and fracture density as a function of the angle between fold axis and maximum horizontal stress at the time of fracturing.
Fault reactivation and structural growth in discrete pulses seem to be prerequisite for the typical fault fracture corridor patterns of type II structures. In many of type II anticlines, the paleo-stress that generated fold-bound faults and fracture corridors is oblique to fold axes. This suggests folding and fracturing took place under transpression and is related to fold reactivation or structural inversion. In either case, existence of a pre-existing structural control is essential, such as regional wrench faults or deep seated basement weakness zones.
Fluvial Facies Analysis Using Gamma Ray Measurements and Outcrop Studies in the Mesri and its Tributary Kuej River in the Mainland Gujarat Region, India
Authors: Bhosle Balaji , Nayak Pravas , Kumar Vikash 
Published: December 2013

Abstract
Exposed outcrop sections were measured in the Mesri River and its tributary Kuej in the Mainland Gujarat region. The studied sections fall in the transition zone between uplands and pediments and thus can give important clues on the behavior of the river and its depositional regime. Mesri river is the first order tributary of the major Mahisagar River south of which lies the oil rich Cambay graban.
The present study includes detailed description of the section, graphic log of the measured section and outcrop total gamma ray measurements at an interval of 15cm. Onsite gamma ray has provided a ready reference for the fining upward cycles with their top and bottom bounding surfaces which is otherwise very difficult to pickup from the exposed section.
The high and low spikes within the fining upward sequences may indicate the sudden change in the channel velocities and thus in grain size. The variation in gamma count can be related to the compositional variations but in this case since the source rocks are similar throughout the drainage basin so the factor of compositional variations can be negated. Both the exposed sections show complex amalgamated fluvial channel fills with moderately to poorly developed flood plain deposits. Most of the deposits are thought to be results of braid and point bars. Various types of calcretes from soft friable to very hard nodular and ferromanganese nodules were commonly seen throughout the studied sections.
Most of the section is moderately to poorly pedogenised. Slabbed sections of the calcretes were studied to see the internal structures. The calcretes offered new insights on the prevailing climatic conditions during the formation of the entire set of deposits. Insitu gamma ray measurements proved useful in identifying the lithofacies variations.
Performance Evaluation and Laboratory Experimental Study on New Gel-Type Profile Control Agent
Authors: Wang Guang , Zhang Dong , Yin Daiyin , Su Yunhang , Ma Chunhua 
Published: December 2013

Abstract
Alkaline/Sufactant/Polymer(ASP) flooding is a new technology of enhanced oil recovery remarkably after polymer flooding. Part of the test blocks of ASP have entered into middle development phase, and achieved better effects of increasing oil and decreasing water. However, Severe heterogeneity of main oil layers leads three elements liquid fingering along the low-permeability reservoir position of every sedimentary units in thick oil reservoir. It causes the low pressure of injection wells, high polymer concentration of production wells and serious inefficient and ineffective circulation of three elements liquid. Research on profile control technology of ASP is promoted to control the increasing speed of polymer concentration of production wells, decrease the inefficient and ineffective circulation of three elements liquid and improve development effect of ASP flooding.
The current profile control agents such as typies of HPAM/Cr3+, HPAM/Al3+ and HPAM/Organic Phenolic cannot fit the alkali environment of ASP. This paper uses the method of contrast test and orthogonal design to recipe a new gel-type profile control agent which can resist the alkali environment.The content of evaluation include impact on the interfacial tension of ASP compound system, impact of the concentration of NaOH on the performance of new profile control agent and impact of slow-release formulation on gelled time. Using heterogeneous core model of flat plate of three layers, four injection and one production wells, the experiments of profile control are conducted in ASP flooding. The results show: adding 0.035 PV new profile agent in the middle of ASP flooding can improve 4.06% of recovery factor more than ASP flooding so that it has a good profile control effect.
The profile control technology for ASP presented in this paper has improved the effect of ASP to a great degree, and it is a promising tool for the successful application of ASP in Daqing oilfield.
Uncertainty Quantification of a Chemically Enhanced Oil Recovery Process: Applying the Probabilistic Collocation Method to a Surfactant-Polymer Flood
Authors: Alkhatib A. , King P. 
Published: December 2013

Abstract
Uncertainty in surfactant-polymer flooding is an important challenge to the wide scale implementation of this process. Any successful design of this enhanced oil recovery process will necessitate a good understanding of uncertainty. Thus it is essential to have the ability to quantify this uncertainty in an efficient manner. Monte Carlo Simulation is the traditional uncertainty quantification approach that is used for quantifying parametric uncertainty. However, the convergence of Monte Carlo simulation is relatively low requiring a large number of realizations to converge. This study proposes the use of the probabilistic collocation method in parametric uncertainty quantification for surfactant-polymer flooding using four synthetic reservoir models. Four sources of uncertainty were considered: the chemical flood residual oil saturation, surfactant and polymer adsorption and the polymer viscosity multiplier. The output parameter approximated is the recovery factor. The output metrics were the probability density function and the first two moments. These were compared with the results obtained from Monte Carlo simulation over a large number of realizations. Two methods for solving for the coefficients of the output parameter polynomial chaos expansion are compared: Gaussian quadrature and linear regression. The linear regression approach used two types of sampling: Gaussian quadrature nodes and Chebyshev derived nodes. In general, the probabilistic collocation method was applied successfully to quantify the uncertainty in the recovery factor. Applying the method using Gaussian quadrature produced more accurate results compared with using linear regression with quadrature nodes. Applying the method using linear regression with Chebyshev derived sampling also performed relatively well. Possible enhancements to improve the performance of the probabilistic collocation method were discussed. These enhancements include: improved sparse sampling, approximation order independent sampling and using arbitrary random input distribution that could be more representative of reality.
The Wafra Second Eocene Heavy Oil Carbonate Reservoir, Partitioned Zone (PZ), Saudi Arabia and Kuwait: Reservoir Characterization, Modeling, and IOR/EOR Evaluation
Authors: Meddaugh W. Scott , Frydl Paul , Dvoretsky Rachel , Gross Steve , Al-Gamdi Saleh , Dull Dennis , Johansen Steve , Caldwell Gary 
Published: December 2013

Abstract
The Paleocene-age Second Eocene reservoir is the second shallowest major reservoir in the giant Wafra Field. The reservoir is part of the Umm Er Radhuma Formation. It occurs at a subsea depth of 1,400 feet and consists of approximately 400 feet of porous dolomite and minor anhydrite deposited on a shallow carbonate ramp. The lower reservoir consists of shallow subtidal sediments; the upper contains stacked subtidal-dominated cycles with thin intertidal/supratidal capping beds. The average porosity is about 30% and permeability average near 300 mD.
Recent stratigraphic and diagenetic studies have improved the characterization of this important heavy oil reservoir. Pervasive dolomitization by seepage reflux of evaporated seawater altered the original depositional fabrics and pore systems. The major diagenetic trends are clearly related to the sequence stratigraphy. The upper portion of the reservoir, informally known as the 1¾ Eocene, is finely crystalline and largely preserves the original subtidal to intertidal/supratidal depositional fabric. The lower reservoir known as the 2nd Eocene, is coarser crystalline and generally lacks discernible depositional fabric. Oil production comes mainly from the lower portion of the reservoir that is characterized by higher permeability, fabric-destructive subtidal dolostone.
Prior to commencing dynamic modeling an EOR screening exercise was completed. Of the eight EOR options considered, only steamflooding and waterflooding were found to be the most viable choices and are the focus of work to date. Updated full field, geostatistical models were generated with reservoir property distributions constrained by stratigraphic layer and the available well and core data. Following up-scaling and history matching, the dynamic model will be used to re-evaluate numerous development options including continued primary development, infill drilling, waterflooding, and continuous steamflooding using various pattern sizes and configurations. Early results from this work along with results from a prior similar study suggest that steamflooding yields higher recovery than other options and that waterflooding also yields good incremental recovery.
Reactivating a Tight Carbonate Reservoir in the Greater Burgan Field: Challenges, Options and Solutions
Authors: Chimmalgi V. S. , Al-Humoud Jamal , Al-Sabea Salem , Gazi Naz , Bardalaye Jayanta , Mudavakkat Anandan , Al-Enezi H. , Al-Zankawi O. , Ahsan J. , Abdulrazzaq E. , Tirkey N. , Kotecha R. , Snasiri F. , Jalan S. , Al-Zaabi R. , Al-Dousari M. , Al-Othman M. , Al-houti N. , Benamer N. , Hai Liu , Elsherif T. , Surjaatmadja J. , Elmofti M. 
Published: December 2013

Abstract
The Mauddud Formation in the Greater Burgan field is a thin carbonate reservoir with very low permeability but with moderate to good porosity and variable fracture density. The formation could be divided into three distinctive layers, based on the structural and digenetic complexities.
Production in Mauddud wells show rapid decline due to tight rock matrix (low permeability). This decline is associated with an increase in Gas-Oil Ratio (GOR) as reservoir pressure falls below the bubble point pressure near the wellbore. Horizontal wells were drilled in an attempt to develop the Mauddud Formation targeting sweet zone. Most of the wells were located in a relative structural high on the up-thrown blocks of the North and Eastern flank of the Greater Burgan field that had the highest likelihood of intersecting fractures. They are mostly adjoining the major faults. There are now around 40 wells drilled in Mauddud including horizontal and multilaterals, most of which became non-producers due to above reasons.
A study has been carried out to evaluate opportunities to revive these wells through available and new technologies in the industry. A detailed geological study incorporating all the available data was carried out initially. Wells were screened for stimulation by using various proven new technologies. Acid Frac, Stage Frac, near well bore SurgiFrac and Matrix Acid techniques have been applied with varying results. Advanced placement technique like distributed temperature profiling was used in some of the jobs.
This paper presents the details of the application of the above mentioned technologies, to the candidate wells and discusses the results. The success of some of these technologies opened up new opportunities for a new beginning to revive the closed wells completed in Mauddud Formation.