bluuebunny/crossref_metadata_2025 huggingface dataset:
Geophysical Exploration Technology Of Complex Volcanic Rock Gas Reservoir
Authors: Feng Zhiqiang , Huang Wei , Feng zihui , Zhang Erhua , Liu Chuanping
Published: March 2015

Lithology identification of complex volcanic rock, reservoir prediction with seismic data and identification of volcanic rock lithology and prediction of fluid property in reservoirs using wireline logging are key techniques for volcanic gas reservoir exploration. Up to now, many exploration wells and a large amount of 3D seismic are performed in volcanic gas reservoirs. Practice and theoretical research has establish a series of effective methods of lithology identification and reservoir and fluid prediction by seismic and wireline logging, with much achievement in gas field exploration evaluation and gas reservoir characterization of Xushen Gas Field.

Instruction

Songliao Basin, located in northern China, is the largest and most prolific non-marine oil-bearing basin. It develops two sets of different Cretaceous formations. The lower rifted formation has alluvial fan to deep lake siliclastic sediments and coal beds, and widely developed volcanic rock. The upper depression formation is mainly fluvial-lucustrine sediments. Being a huge oilfield, Daqing Oilfield has oil reservoirs discovered in sandbodies in fluvial and deltaic facies of upper depression formation in 1959, and large gas reservoirs discovered in volcanic rock in lower rifted formations in 2002. Volcanic gas reservoirs have burial depth of 3000m~5500m. High pressured fluid history of the basin causes difficulty for tight glutinite in this depth to form gas reservoir. Compared with siliclastics, volcanic rock has not only variety of lithology types and pore types, but also little research result. Study on field crops and modern volcanoes process establishes structural patterns for different types of volcanoes. Based on core analysis data of large amount of volcanic rock, and combined with wireline logging and gas testing data, a series of exploration techniques including lithology identification and reservoir and fluid prediction are developed for volcanic gas reservoirs[1].

1 Seismic identification technique for volcanic rock body

Difference of eruption periods and scales cause variety of lithology and complexity of depositional structures. Weathering and host rock also cause variety of seismic structures of volcanic rock.
Process For Improved Mercaptan Removal
Authors: Cadours Renaud , Shah Viren , Weiss Claire
Published: March 2015

Removing mercaptans from sour natural gas has always been considered as a challenge. This is becoming an even more important issue with the global trend towards more stringent specifications for commercial gases.

Amines have been extensively used because of their ability to meet the most severe H2S and CO2 specifications and their very high acid gas selectivity over hydrocarbons, but present very limited mercaptans removal performances. They require an additional treatment step to achieve the total sulfur content specification in the exported gas. Hybrid solvents are more efficient in removing mercaptans, but have the disadvantage of poor acid gas selectivity over hydrocarbons, resulting in hydrocarbon losses with the separated acid gases.

Total, taking advantage of its extensive know-how and experience in acid gas removal with amine mixtures, has developed the HYSWEET® process, using a new hybrid solvent formulation allowing simultaneous absorption of acid gases and of mercaptans, with limited coabsorption of hydrocarbons. The solvent was selected at the laboratory scale, with a particular attention given to operation related constraints e.g., cost, corrosion, foaming, degradation…etc. The new solvent's acid gas and mercaptans removal performances were then validated on a pilot rig.

The performance of the HYSWEET® process has been assessed for several field applications, and compared with the performances of conventional amine processes. This allowed evaluating the potential gain achievable by the implementation of the new hybrid solvent. The study leads to identify the application cases for which the new hybrid solvent will allow an economic and complete mercaptan removal without any additional treatment, and a perspective of reduction of the additional treatments for the other cases. Besides an economical mercaptan removal, the new hybrid solvent allows a significant reduction in the energy consumption.

The results of the techno-economic evaluation of the HYSWEET® process have been confirmed during the first successful industrial application at the Lacq sour gas plant in 2008. Half of the gas production is now treated with the hybrid solvent, allowing the plant to achieve high global mercaptans removal.

These results are fully documented in the paper, demonstrating that the newly developed process is a good contender for the development of new sour gas fields to achieve the increasingly stringent commercial gas specifications.
Active WF ( Pattern) Management Through Modern Online Production Data Base Systems Using Classical Techniques : A Case Study On Heavy Oil Fields In South Oman
Authors: Gupta Vipin Prakash , Al-Saadi Faisal Salim , Al-Belushi Abdulaziz Hikal
Published: March 2015

Water flooding has been used successfully in heavy and viscous oil fields since last fifty years. Though characterized by low recoveries and high cost due to adverse mobility ratio, waterflood is still an attractive option before embarking on expensive EOR solutions.

One of the key elements to success of waterfloods in heavy oil is well and reservoir management. This paper illustrates the use of daily production data to set up systems that indicate the health of waterflood through use of classical techniques so that they are readily available on a demand to know basis for any hierarchy of production systems; field pattern, groups, individual patterns etc. The observations and results can then be applied to take proactive measures for preventive management.

To manage water floods in a dynamic scenario, reservoir engineers need to watch them closely, analyze them for anomalous behavioral trends in a continuous fashion and be able to apply remedial measures as they manifest themselves. This can not be done through numerical simulation models, first, because of the high cost and time constraints and secondly because the models usually are highly simplified and are constructed using an average property data.

Numerous techniques have been developed by various people working on waterfloods around the world in last 4 decades. Most of these techniques are in the form of diagnostic plots based on easily available data. This paper is an effort to put many such methodologies in a structured format which will enable the engineer to monitor the floods in a systematic and step wise manner. It is intended to move personnel involved in waterfloods up a learning curve and provide them with a toolset to not only measure but improve the flood efficiency. It will assist reservoir engineer's production technologists and development geologists who are involved in or are contemplating waterflood operations.

Introduction

Reservoirs communicate with engineers through production data. This language, if interpreted correctly can lead the engineer to understand the sub-surface flow process and thereby improve the efficiency of the system. This paper uses only production data with general use software applications like spreadsheet/ data base systems etc to develop tools that help the engineer to understand the message of reservoirs.

The paper reviews and explains in detail along with application on live data, techniques to estimate volumetric sweep efficiency, prediction of pressure response (using net voidage), interpretation of injection behavior (Hall's Plot), predicting water source in a oil producer (WOR techniques), using heterogeneity index to priorities options and prediction of ultimate recovery through X-plot calculations and a host of minor techniques that help in understanding & visualization of waterflood behavior.
Technology And Application Of Recycling Produced Water From Heavy Oil Production To Steam Generators
Authors: Xie Jiacai , Liu Xilin , Xie Wenyan
Published: March 2015

This paper presented the results of laboratory studies, pilot field tests and field applications of produced water recycling to steam generators, discussed produced water characteristics, removal of oil and suspended solid, hardness and silica. Up to now, 119, 000 m3/d produced water is recycled to steam generators in china, and realized the goal of uniting the economic, environmental and social benefits together.

INTRODUCTION

Heavy oil is an important national strategic resource and the heavy oil in China is mainly produced by steam injection with the annual oil production of about 15 million tons, fresh water consumption of 1.5×108m3 for steam injection and produced water from heavy oil production of 2×108m3. How to effectively treat the produced water and realize cyclic utilization to save energy, reduce emission and protect the environment is an important issue faced both at home and abroad. The recycling of produced water from heavy oil production is an important technology used in oil production to develop cyclic economy and save energy and reduce emission. Because the produced water has complex compositions, many technical problems exist in effectively treating the produced water to be the feed water for steam generators, including oil-water separation, eliminating the hardness of the high temperature, high salinity and high organics producede water, eliminating SiO2 in the produced water, highly siliceous produced water treatment for steam generators use and oily sludge utilization.

Since 1998 when lab research was started, through tests at different levels, five key techniques have been developed: high efficiency demulsifiers and related techniques for oil water separation;produced water hardness elimination by the volume change during the process of alkali regenerating out of the modified weak resinic acids and its features of eliminating pollution and restoring activity;desiliconization of produced water by combining active magnesium oxide and inorganic aluminum salts and organic flocculants;eliminating scale buildup in boilers and improving the technical limit for SiO2 in the feed water by further eliminating the micro scale forming ions in the produced water with chelating resin;making new compounded fuels out of the recycled oily sludge.

The technology has been widely applied in Liaohe Oilfield as well as in Xinjiang, Henan and Shengli Oilfield. Since 2002, nine treatment facilities for produced water from heavy oil have been set up with daily treatment of 11.9×104 m3 of produced water. With the technology, fresh water of 4343×104m3 is saved every year, saving fuel oil of 204,000t/a, recovering oil of 175,000t/a, reducing the emission of CODcr by 22,800t, resulting in direct economic benefits of 2.19 billion RMB, achieving tremendous economic, environmental and social benefits.
ExxonMobil Production Facility Integrity Management System
Authors: Killian Keith Edward , Lee Mitchell
Published: March 2015

The paper will provide an overview of the system developed and adopted by ExxonMobil Production Company for managing integrity and reliability of production facilities within our Operations Integrity Management Framework. The paper will cover principles, scope, key elements, processes and workflows associated with the Facility Integrity Management System (FIMS). It will also discuss critical success factors for effective implementation and lessons learned.

Safety, health and the environment are of the highest priority. Production downtime and unplanned maintenance can have significant financial and reputation impacts. Effective facility integrity and reliability management is a key element to achieving desired performance in these areas. Our structured approach to Equipment Class Program Design, Execution, Stewardship and Continuous Improvement has provided clarity on key maintenance, testing and inspection activities, and their effectiveness at achieving Program objectives. Learnings can then be incorporated back into the Program to improve effectiveness and efficiency.

The general principles outlined in this paper will provide insight on the approach to successful facility integrity and reliability management and critical success factors. The experience in developing and implementing the system will be of direct interest to professionals engaged in engineering, maintenance and operations of facilities related to oil and gas production.

Introduction

Overview

ExxonMobil remains steadfast in its commitment to excellence in Safety, Security, Health and Environmental (SSH&E) performance. In addition, high emphasis is place on production reliability and efficient, effective maintenance of our operations. ExxonMobil's Operations Integrity Management System (OIMS) is a cornerstone in managing SSH&E risk and achieving excellence in performance, and includes specific expectations for facility integrity and reliability management. ExxonMobil Production Company has addressed this aspect of OIMS through a comprehensive Facility Integrity Management System or FIMS. FIMS addresses the standards, processes, best practices and activities necessary for managing integrity and reliability of critical facilities within our production operations, and has been successfully implemented throughout ExxonMobil's operated production business globally.
Corrosion Modeling Within an Integrated Corrosion Prediction Approach
Authors: Sun Wei , Geurts Kevin R. , Pugh Dylan , Pacheco Jorge Luis , Monahan Craig C. , Franco Robert J. , Norman David
Published: March 2015

This paper describes an integrated approach, based on corrosion modeling and laboratory testing, to optimize the use of carbon steel in corrosive service for applications such as downhole tubulars, pipelines, and facilities. This approach presents economic advantages, such as reducing the use of expensive corrosion resistant alloys, while ensuring the operational integrity of equipment and facilities. A key part of this integrated approach is to apply reliable corrosion models underpinned with laboratory data. To be most effective, the models should account for the relevant chemistry and physics of the corrosion process, including the effects of detailed water chemistry, liquid hydrocarbons, and the degree of protection from iron carbonate or iron sulfide scales. Ideally, models should account for variations in conditions and flow characteristics along the length of a wellbore or pipeline. Case studies are presented that demonstrate how corrosion modeling in conjunction with laboratory testing may be used to the selection of validate carbon steel for challenging applications.

Introduction

Although high cost corrosion resistance alloys (CRAs) were developed to resist internal corrosion, carbon steel is still the most cost effective material used in oil and gas production. It is very important to develop an integrated corrosion prediction approach for optimizing the use of carbon steel in corrosive service while ensuring the operational integrity of equipment and facilities.

Both corrosion models and laboratory testing are frequently used in this industry to make lifetime predictions of facilities using carbon steel and further to make decisions on materials selection. Corrosion models, including empirical, semi-empirical, and mechanistic ones, have been developed over the past several decades to predict corrosion of carbon steel 1–6. These corrosion models can provide engineers quick and economical corrosion predictions. Most of the models were validated by laboratory data and/or field data. Empirical and semi-empirical models usually provide reasonable predictions inside of their validation range but poor predictions outside of their range. Mechanistic models generally can extrapolate to conditions outside of their validation range and remain accurate to a certain degree. Consequently, one should always understand the validation range and limitations of the models to apply these correctly. Moreover, although part of corrosion mechanisms are well understood in lab investigations, due to the complexity in production operations, it is still challenging to apply lab short-term testing results and corrosion models to predict corrosion of facilities for twenty to thirty years of service. An integrated approach was therefore developed by ExxonMobil1 to apply a reliable corrosion model in conjunction with laboratory testing for predicting corrosion in oil and gas production.
Optimizing Electroosmotic Flow Potential for Electrically Enhanced Oil Recovery (EEORTM) in Carbonate Rock formations of Abu Dhabi Based on Rock Properties and Composition
Authors: Haroun Muhammad Raeef , Chilingar George V. , Pamukcu Sibel , Wittle J.K. , Belhaj Hadi , Al Bloushi Mariam N.
Published: March 2015

Among the leading emerging technologies for in-situ oil recovery is the use of an electrokinetic technology known as electrically enhanced oil recovery (EEORTM)i. Electrokinetic methods are continually tested and improved both in the laboratory and in the field to render them highly feasible for increased oil recovery. The effectiveness of the process to enhance the flow and production of both light and heavy crude oil from sandstone reservoirs have been demonstrated in the laboratory by researchers for the last four decades. Successful but limited field applications, both in-situ and ex-situ have also been reported for the same duration of time. There has been little work done on the applicability of the technology to carbonate rock reservoirs, owing to predicted high energy consumption due to low clay content formations and high salinity environments. Yet, compared to currently incurred high costs of conventional electrical oil recovery which depends on joule heating of the formation, electroosmotic mass transport may offer a feasible option to augment the flow of these large volumes of crude oil both onshore and offshore.

A great additional incentive is that EEORTM can be engineered as a truly green technology, where there is no water consumption, and no air, water, and formation pollution. The technology can be applied with no depth limitation in-situ rendering it even more attractive in remote operating locations as well as the environmentally challenging ones. This paper addresses the first attempt undertaken at the newly-established Electrokinetic Laboratory of the Petroleum Institute in Abu Dhabi, U.A.E. to determine the efficacy of electrokinetic technology in EEORTM tested on field collected data samples of Abu Dhabi. The results of the initial tests conducted on field retrieved specimens of Abu Dhabi on-shore carbonate reservoir rock candidates from several formations in high salinity environments that contained various crude types are reported.
Production Of Heavy Lubricating Oil Base Stocks And Analyses By Using A New Method HPLC
Authors: Aboul-fotouh Tarek Mohamed , El-Shafie Masoud , Mohamed Soad
Published: March 2015

The main objective of the present investigative work is the experimental production of heavy lubricating oil base stocks and the study of the effect of chemical composition on physico-chemical characteristics of the prepared lube oil samples. In the first process, solvent dewaxing, the mixture of methyl ethyl ketone and methyl isobutyl ketone (MEK/MIBK) is used as a recent solvent in the dewaxing process to obtain a significant yield of low pour point products and to compare this mixture with MEK/toluene which is used in the industry process. Solvent dewaxing process is carried out at - 10°C using the mixture of MEK and MIBK (40/60 by wt.) with solvent oil ratio of 3:1 for the selected raffinates, heavy refined oils, from furfural and NMP extraction processes. The dewaxed oil samples were analysed to evaluate their physico-chemical characteristics by the standard methods outlined in ASTM, IP and UOP books such as the standard methods for wax content, pour point, sulfur content and structural group analysis by n-d-M method. The results show that the use of MEK/MIBK mixture instead of MEK/toluene at -10°C achieves an increase in filtration temperature with about 5°C with subsequent a reduction in the cooling rate of process.

In the second process, clay-alumina finishing process as a percolation process, the dewaxed oil samples are treated to reduce the sulfur content and remove the nitrogen, oxygen and other undesirable compounds completely. The local natural clay (fuller's earth) with the particle size of 30–60 mesh and aluminum oxide 90 active neutral (Merck) with the particle size of 70–230 mesh are used as a mixture in this process. The finished lube oil samples are analysed to evaluate their physico-chemical characteristics by the standard methods outlined in ASTM, IP and UOP books. In addition, heavy grades are analysed by the high performance liquid chromatography (HPLC) after the solvent extraction and clay-alumina finishing processes. The chromatograms reveal the reduction in aromatic peaks after clayalumina finishing process and the reduction in saturate humps after the dewaxing process. Finally, the results show that high quality lube oils with good thermal and oxidation stabilities are produced.
An Original Technique to Characterize Naturally Fractured Reservoirs from Pressure Transient Analyses
Authors: Elkewidy Tarek Ibrahim
Published: March 2015

This new technique is introduced to characterize all kinds of naturally fractured (secondary porosity) reservoirs, including carbonates, basements, and clastics on the Megascopic scale of well testing delineation. The technique is based on an original view of pressure transient data (buildup). In fact, this technique bridges between the Macro, Meso, and Megascopic scales of reservoir characterizations.

Conventional well testing analysis techniques, e.g. Horner method, do not often work for naturally fractured reservoirs since they are based on a homogeneous reservoir model. In addition, all available techniques to characterize naturally fractured reservoirs from pressure transient analyses are very much theoretical models based on unrealistic geometrical assumptions. They lack practical applications and produce limited information.

The new technique has the merit of working on real reservoir data. It utilizes pressure buildup data through the fact that formation fluids travel across different systems in heterogeneous naturally fractured reservoirs; matrix, fractures and the damaged area. A unique graphical characterization of shut-in well pressure versus time will illustrate the effect of fluid movements from the matrix system (or the tiny fractured system) through the main fracture system and across the damage area, if any, into the well. Fluid movements through each system are represented graphically. The technique is further optimized through application of pressure derivative methods to yield a very characteristic graphical representation (triangle)of each hydraulic "flow" unit in the reservoir.

The presence of the triangle sides can be used to confirm the existence of a secondary porosity system (fractures) and/or damaged area. The slopes and intersection values of the straight lines are utilized into exclusive formulas to yield the most important petrophysical and engineering parameters about the heterogeneous naturally fractured reservoir (and, in many cases, other kinds of reservoirs) including: effective fractures, matrix and skin systems volumes, partitioning coefficient, fracture intensity index, formation resistivity factor, formation tortuosity, effective drainage radius, damage radius, effective cementation exponent, fracture porosity, matrix porosity, storativity ratio, in addition to fracture permeability, matrix permeability, damaged (skin) permeability, average permeability, pressure drop across the damage area, skin factor, damage permeability, average/dimensionless diffusivity factor, flow efficiency, damage ratio/factor, economic implication of formation damage, average hydraulic "flow" unit quality index. This document and presentation will cover the theory behind the technique and present actual field application examples.
Enhancing the Interpretation of Rift Structures in Sudan Using AVO Analysis and Seismic Inversion
Authors: Mahgoub Mohamed Ibrahim , Padmanabhan Eswaran
Published: March 2015

Uncertainty in structural complexities and rock heterogeneities is a major challenge that controls oil exploration and drilling operations in the rift basins of Sudan.

Wide ranges of depositional environments developed within these reservoirs: e.g., fluvial, shallow and deep lacustrine, fluvio-deltaic systems. Multi-phase rift development from rift initiation to late post-rift introduced good oil traps and very heterogeneous reservoir rocks situations.

Advances in seismic inversion techniques and AVO analysis maximize the probabilities of valid interpretation and lithology delineation in such rift structures thereby reducing the associated uncertainty limit. Accuracy of interpretation depends on the quality of seismic data. Therefore, there is an urgent need to introduce innovative techniques in seismic processing to improve seismic resolution prior to any inversion work.

This paper explains an-integrated workflow using seismic data conditioning and inversion methods applied for detailed interpretation and advanced reservoir characterization applications in these rift basins. The seismic data conditioning and inversion workflow implementation comprises three main steps: beginning with data conditioning (seismic and logs), wavelet estimation, and relative acoustic impedance inversion.

The conditioned seismic and relative acoustic impedance volumes are used to improve horizons and faults. This interpretation can be used further to build a low-frequency models for absolute acoustic impedance inversion and porosity transformation.
Sinphuhorm, Thailand Pipeline Integrity Management Utilizing Advanced Monitoring Techniques
Authors: Cenegy Lawrence Michael , McAfee Clyde Alan , Engchanil Rachan , Thatsana Apisith
Published: March 2015

As a primary energy source, natural gas continues to play a major role in meeting Thailand's energy requirements and is preferred for generating the country's electricity. As energy demand increases, a fully integrated pipeline integrity program for wet gas pipelines becomes necessary to ensure safe production from Thailand's gas fields. This paper presents an overview of the corrosion mitigation and monitoring strategies implemented on a 63.5 km (40 mile) long, 385 mm (15.2 in) maximum internal diameter, carbon steel wet gas pipeline. The pipeline is in Khon Kaen Province, located northeast of central Thailand.

Extensive pre-startup analysis was conducted, such as pipeline dynamic flow modeling and corrosion prediction modeling, from which the final corrosion management strategy was derived. Advanced corrosion measurement tools developed for continuous data collection, such as high-resolution metal loss probes and high-sensitivity ultrasonic wall thickness transducers, are discussed, and performance data included. Key performance indicators for corrosion control, including hydrogen sulfide measurements, iron counts, corrosion inhibitor residuals, and sulfate reducing bacteria, along with pipe wall corrosion measurements and cathodic protection potentials, are also considered in the paper.

Recent in-line inspection data was used to correlate the continuous monitoring data collected over the last several years with the recorded pipeline condition to evaluate the effectiveness of the corrosion management program. The evaluation of the overall success of the management program is discussed, along with lessons learned for future reference.

Introduction

Because Thailand has limited domestic oil reserves of around 183 million barrels, imports make up a large portion of the country's oil requirements. Thailand does, however, have large proven reserves of natural gas (12 trillion cubic feet estimated as of 2007) located both offshore in the Gulf of Thailand and onshore. As a result, natural gas plays a major role in meeting Thailand's energy requirements, both as a primary energy source as well as the preferred fuel for generating the country's electricity.

Although annual gas production has risen over the last few years to 882 billion cubic feet, the increased production has not been sufficient to meet domestic needs, and the country remains a net importer of gas (APEC 2010).

As energy demand increases, the need for a fully integrated pipeline integrity program for wet gas pipelines becomes necessary to ensure safe production from Thailand's gas fields.

The Sinphuhorm Facility—Background

In 2006, an operator in Thailand constructed the Sinphuhorm Gas Processing Plant (GPP) and associated facilities at Orbortor-Kudnam Sai District in northern Thailand, about 90 km south of Udon Thani and 30 km from the city of Khon Kaen, shown in Fig. 1.
Ranking Production Potential Based on Key Geological Drivers - Bakken Case Study
Authors: Pilcher Robin S. , McDonough Ciosek Jessica , McArthur Kelsey , Hohman John C. , Schmitz Peter
Published: March 2015

The Bakken Play is a lithologically complex, mixed carbonate-clastic and low porosity-permeability petroleum system comprised of juxtaposed source rocks and reservoir intervals. The play spans variable source maturity, reservoir pressure and temperature, and fluid type. The target reservoirs are thin (below seismic resolution), gently-dipping and variably affected by subtle structure, faults or natural fractures.

As a continuous oil accumulation with an unconventional development model, numerous horizontal wells with multi-stage completions will be required to develop the Bakken Play. Ranking future drilling locations is a critical step in planning the development strategy and optimizing the economics of the play. Ranking methods are typically based on prior well performance; however, in the Bakken Play we recognize that numerous non-geological parameters associated with drilling, completions, and production operations contribute to well performance. In this paper we describe a methodology to assess the underlying productivity potential of the reservoirs based on key geological drivers.

With an extensive well log database, petrophysical uncertainty can be addressed and stock-tank oil originally in place (STOOIP) calculated and mapped.

Nevertheless, the relationship of STOOIP to production performance remains weak due to drilling, completion, and production variables. In this study we apply geological modifiers to the calculated in-place resource to better represent the productivity potential. Geological modifiers include source maturity and charge access, reservoir facies and properties, structure (trap and natural fractures), overpressure, and fluid properties.
Successful Application Of Ultrasound Technology To Detect Sand Producing Intervals In The Wellbore
Authors: Mohd Daud Farik , Jusoh Hasni , Mohamed Azhan , Then Eii Feng , Batumelai Sathish Kumar
Published: March 2015

Sand production in oil and gas wells not only poses a serious threat to hydrocarbon production, but can also cause extensive damage to equipment, such as subsurface tubing, surface valves and pipelines. Produced sand is also an environmental hazard, and needs to be disposed of in an environmentally safe way. Effective sand management is therefore a major concern in the oil and gas industry.

The key challenge is to optimize hydrocarbon production by minimizing the production of sand and in doing so reduce the damage caused to well completions and surface equipment. On a sand-prone well, this is typically done by identifying a maximum sand free rate (MSFR), and then limiting production to this level. Conventional sand detection methods rely on surface measurements. However, these methods do not provide a complete picture of the sand production down hole. To gain a more comprehensive understanding of the problem, sand needs to be detected at its point of entry into the well bore. In this way, the best remedial treatment can be designed.

To answer this requirement, an ultrasonic sand detection tool has been developed. The tool detects ultrasound energy generated by sand grains as they enter the well bore and strike the tool in a radial manner. Sand moving parallel to the well bore axis is not detected, thus the tool can indicate the exact entry point of sand, anywhere along the producing interval. The operator can then specify the most appropriate and cost effective remedial action, such as installing sand screens or applying chemical treatments. By employing such a tool, the cost of remedial action can be minimized and hydrocarbon rates can be optimized to achieve sand-free production. The tool can also be used to evaluate the performance of sand screens and other control devices, and if run in tandem with production logging tools, can monitor sand production in conjunction with well performance.

This paper presents the results of a case study where a downhole ultrasonic sand detector was used to monitor sand production in five gas-producing wells from the Northern Malay Basin. The methods behind this "sand survey" are presented, along with a description of the tool.

Introduction and Background

Carigali Hess Operating Company Sdn. Bhd. (Carigali Hess) operates the Cakerawala, Bumi, Suriya and Bulan gas fields in Block A-18 of the Malaysia-Thailand Joint Development Area (MTJDA). Figure 1A shows the geographical location of the MTJDA in relation to Malaysia and Thailand, while Figure 1B illustrates the current arrangement of platforms and pipelines operated by Carigali Hess in the block.
Review of Ultrashort-Radius Radial System (URRS)
Authors: Marbun Bonar Tua Halomoan , Zulkhifly Samuel , Arliyando L. , Putra Syatria Kumala
Published: March 2015

The objective for the Ultrashort-radius radial system is to provide an extended wellbore radius by means of multiple radials from a vertical wellbore (i.e., to effect an extended completion or extended pipe perforations). It can be applied both in new and old wells. Its main technique is to use high pressure jet flow energy, given by a special high pressure jet tube, to penetrate and elongate a number of lateral well bores radiated from the main well bore in the same layer or different layer so as to expose the pay zone as much as possible and increases the Enhanced Oil Recovery. The choice of radial length, number of radials, and radial array is a function of the reservoir properties.

The research reported herein discusses the application of the URRS. The specific variables like reservoir thickness, vertical and horizontal permeabilities, oil properties, well spacing, outer-boundary reservoir pressure, gravity drainage, thermal and non-thermal processes and impermeable partings within the reservoir has been studied together with drilling operation parameter like casing design, drilling fluid design, radial drilling equipment, Bottom Hole Assembly to optimize the drilling process and completion of the URRS at field. This paper also briefly describes the next development and its problems that must be economically and feasibility resolved later.

Introduction

The increasing of energy demand, especially in oil and gas term, has driven the invention of new technology and improvement in field developing. Horizontal drilling technology has emerging since a few decades ago. In many brownfields, horizontal drilling is used to increase hydrocarbon production by increase footage of the production zone contacted by the borehole. Horizontal drilling increases the production rate and ultimate reserves recovered. There are several types of horizontal drilling (The detail of horizontal drilling and well classifications can be seen in Tab.1 and Fig.1)1:Long Radius (LRH) = less than 6o/30m.Medium Radius (MRH) = less than 6o/30m - 40o/30m.Short Radius (SRH) = greater than 40o/30m, quite often build rates of 100o/30m.
An Experimental Investigation on Use of Nanoparticles as Fluid Loss Additives in a Surfactant - Polymer Based Drilling Fluids
Authors: Srivatsa Jayanth T. , Ziaja Malgorzata Barbara
Published: March 2015

As we approach an age of deeper discoveries in hostile environments, we need to either improve on existing drilling fluids or design new ones in order to meet the technological demands for success. The filtrate invasion is the most critical parameter that may cause a wellbore failure if not properly controlled. Also, the filtrate induced formation damage and problems with filter cake removal adversely affect the well productivity or injectivity.

The literature survey reveals the advantages of polymer, surfactant and Nanoparticles systems independently and also combination of two of these. A study is necessary to see the effect and advantages of combining all three systems together i.e. a Polymer-Surfactant-Nanoparticles system and to measure the rheological and fluid loss characteristics of the complex combined drilling fluid system. An attempt to study the same has been made in paper. Therefore, in this paper the authors present the results of testing the rheological properties and the API filtrate loss of a Bio-Polymer and Surfactant blend system with addition of Nanoparticles and compare the fluid loss reduction by using Nanoparticles as fluid loss additive with an industry standard polymer-based fluid loss additive

The objective of this research was to study the effectiveness of a Bio Polymer - Surfactant fluid blends, containing Nanoparticles as fluid loss additives in reducing the filtrate losses to the formation by forming a thin, non-erodible filter cake.

Laboratory experiments were carried out for the different combination of polymer and surfactant with varying concentrations to find the optimum of fluid performance. The laboratory measurements included measuring mud weight, pH, viscosity, gel strength, standard API filter test and High Temperature High Pressure (HTHP) test using Permeability Plugging Apparatus.

Presented results show that sized silica nanoparticles can be used instead of sized calcium carbonates which are a very effective inorganic bridging agent, however, difficult to maintain. The polymer - surfactant blend is better in rheological properties as well fluid loss properties than a Bio-Polymer based fluid or Surfactant based fluid. It captures the merits of both fluid systems. The nanoparticles play an important role in reducing the fluid loss of the individual fluid systems.

Also, the nanoparticles based Polymer-Surfactant blend is a good solution for solids free reservoir drill in fluids for horizontal shale drilling applications. The nanoparticles is most effective for shale drilling application as it can penetrate the pores of the shale and act as a bridging material and causing wellbore strengthening.
Searching for the Missing Link: The Regressive System Tract - Seismic Stratigraphic Evidence from the Southern Gulf of Thailand
Authors: Pigott John D. , Zhai Rui , Pigott Kulwadee , Tonianse Tatiya
Published: March 2015

High resolution seismic stratigraphic and geomorphic analysis of some 600 km2 of offshore 3D seismic data from the southern Gulf of Thailand reveal the preservation of a complete eustatic cycle on a Quaternary tropical coastal plain that is periodically affected by oscillating sea levels. While the dominantly aggradational interfluvial coastal plain records only the classic deltaic Parasequence Set signatures (PSS) of the Highstand Systems Tract (HST), Low stand Systems Tract (LST), and Transgressive Systems Tract (TST) stages capped by regionally pervasive ravinement surfaces, the erosionally incised intrafluvial rivers on the plain record an additional PSS, which is defined as the Regressive Systems Tract (RST). The RST is represented by downward stepping fluvial terraces in response to downward stepping base levels. Placing coastal river deposits within a sequence stratigraphic framework and the recognition of the RST afford significant insight into both the dynamic response of rivers to eustatic changes and to their petroleum system potential. The four complete PSS observed within the intrafluvial alluvial plain and their major characteristics are:1. HST: Highest base level where channels are widest, have the lowest gradients, and carry the finest sediment load. Such reservoirs would have poorest sand quality and seal potential.2. RST: Falling base level where channels tend to have lower width/thickness ratios and lower sinuoisities. Stages of erosional downcutting into the preceding HST deposits develop with the formation of terraces of lateral accretion units which can be seismically imaged as alternating oblique bands of amplitude polarity reversals in cross section and zebraic in plane section. Good reservoir sand quality and vertical but laterally disconnected geometries occur.3. LST: Lowest base level with the occurrence of maximum downcutting of principal channels and the development of serrated subordinate tributaries. Fluvial channels exhibit low sinuosities with potentially good reservoir continuity, sand quality, and charging potential.4. TST: Rising base level in which channels progressively widen and the subordinate tributary boundaries flood, yielding less favorable reservoirs but with potentially good source and seal potential.
Application of Distributed Temperature Measurements to Estimate Zonal Flow Rate and Pressure
Authors: Muradov Khafiz Mikhailovich , Davies David R.
Published: March 2015

Wells equipped with optic fiber Distributed Temperature Sensors (DTS) provide real-time downhole flow rate information offering an opportunity for effective production management in real-time. The downhole information can also be used to update the reservoir model, leading to a better description of the reservoir, an improved performance prediction and to a more effective, reservoir depletion strategy. Numerous publications describe smart well control and monitoring systems and improved production case histories.

Temperature measurements play important role in downhole monitoring in intelligent wells. DTS analysis is specifically important for wells with a number of production or injection intervals where the rate allocation is required for the effective reservoir performance and recovery monitoring. Distributed temperature data can be either analyzed using classical (production logging) methods of thermometry or calculated with recently developed models and software tools, the matched measured and calculated temperature profiles being used to estimate the wellbore flow rate distribution.

In this paper we will provide an overview of the currently applied distributed temperature monitoring and interpretation methods. Novel approaches for DTS data analysis measured during multi-rate well tests and for advanced completions with their complex flow paths will be presented. The approaches are mostly based on the robust, classical methods and can be extended to zonal flow rate as well as pressure calculation. Utility of the distributed data interpretation workflows will be demonstrated.

The proposed workflow can be used for zonal flow rate and pressure allocation in wells equipped with DTS. It extends the information capacity of DTS data towards more effective well and reservoir performance monitoring level.
Examples of 4D Studies from Kuwait
Authors: El-emam Adel Hassan , Zahran Wael Abdel-alim
Published: March 2015

Introduction

The use of the Time Lapse, or 4D, seismic technology is well established in the marine offshore seismic environment, this technology is not so well established yet in the land seismic environment

The effectiveness of 4D seismic surveys for monitoring production-induced effects in the reservoir is determined by the magnitude of the change in seismic response and by the repeatability of the seismic experiments over the time periods.

KOC has recognized the significance and potential of 4D seismic as a powerful and cost effective tool for reservoir management. KOC also comprehends the need to test and evaluate all available, and the emerging, technologies to make 4D successful. In this paper we review several 4D examples, with emphasize on a repeatability study onshore conducted in North Kuwait and a 4D reservoir study performed in Minagish field; West Kuwait.

History of 4D seismic in Kuwait

Between 1996 and 1999, during the acquisition of the 2D and 3D seismic surveys across the State of Kuwait, KOC Exploration Group made the decision to evaluate the effectiveness of 4D seismic as a tool for reservoir production monitoring over some of its key producing fields.

Four pilot areas were selected over the Minagish, Raudhatain, Sabiriyah and Burgan fields (Figure 1). A small time lapse pilot seismic surveys varying in size from 9 Km² to 50 Km² were acquired and processed. The two pilots with the greatest potential were subsequently re-processed using the latest 4D analysis and processing techniques.

In 2004 KOC demonstrated its position at the leading edge of Time Lapse technology by carrying out the first seismic study in the Middle East using single sensor seismic over the 4D pilot area in the Minagish field.

The fine spatial sampling obtained by single sensor technology provides highly effective coherent noise attenuation, by attenuating such noise the signal to noise levels of Time Lapse data improved to the point where the subtle changes in acoustic impedance due to fluid changes in the carbonate Minagish Oolite reservoir could be more effectively detected.
Integration of Basin Modelling, Uncertainty Analysis, HC Charge Volume Assessment in Petroleum Exploration Risk Evaluation
Authors: Liu Jianchang , Katz Barry J.
Published: March 2015

Recent developments in hydrocarbon (HC) exploration have necessitated the strengthening and greater integration of geologic model building. Robust basin modeling requires a two-step procedure consisting of constructing reliable input frameworks that are consistent with available data and geologic interpretations and related geohistory processes and conducting basin simulation tests to explore and determine the confidence level of modeling results.

Integrating structural components such as faulting and salt movement is a key element and requires their restoration through time. These restorations impact our understanding of basin development, HC migration patterns, fetch areas, as well as the assessment of potential HC volumes.

The granularity or resolution of the stratigraphic input may also alter the modeled migration pattern, including the relative importance of lateral and vertical components and distance.

Key modeling input parameters include the source rock distribution through time and space. This input can be developed through the integration of geochemical data with stratigraphy, paleo-bathymetric framework, and other basin specific conditions (e.g., paleolatitude). As a result, a 3-D framework of organic richness and kerogen type can be developed.

The restorations and interpretations are imbedded within the basin modeling workflow and iteratively interact with the basin's burial history modeling. This iterative approach along with the numeric simulator accomplishes the integration and optimization of the input geologic model and directly yields more realistic modeling results consistent with the basin's specific geology.

Finally, in order to capture the full range of uncertainty in the petroleum system and to objectively evaluate the hydrocarbon potential and risks in the basin, a suite of simulations need to be performed using a probabilistic approach to determine the confidence level to be placed on the HC volume potential and risks in the analyzed basin.