bluuebunny/crossref_metadata_2025_split huggingface dataset:
Role of Detailed Reservoir Characterization and Lateral Placement on Well Performance in the Marcellus Shale Gas Reservoir
Authors: Shebl M.A. , Nyaaba C. , Yalavarthi R. 
Published: March 2015

Abstract
Development of a shale gas reservoir is dependent on petrophysical parameters indicating gas availability and the success of well completion in accessing this gas. To evaluate shale gas reservoirs it is essential to understand and evaluate the reservoir's heterogeneity and its effect on its rock quality. The benefit is identification of better hydraulically-fracable zones amongst the best reservoir quality rock. Thus this paper illustrates how petrophysical analysis, in conjunction with geomechanical modeling, aids in determination of the optimum lateral placement and fracture design for a successfully producing well.
Petrophysical analysis was performed to determine the reservoir quality, Original Gas-in-Place (OGIP) and the geomechanical property distribution. Based on the distribution of these petrophysical properties, different lithofacies were identified; potentially fracable zones and fracture barriers were predicted. Case histories of two wells are presented to demonstrate how detailed petrophysical analysis assists in determining the correlation between lateral placement and well performance. The first well was drilled in a good reservoir quality interval with the lateral placed in brittle zone in-between rocks with high gas content. As a result, it had good performance with a higher linear transient productivity index. The other well was drilled in a bad reservoir quality interval with the lateral placed in a brittle zone with low gas content and lower performance.
First Steps of Channel Fracturing in Russia Set New Directions for Production Increase of the Oil Fields
Authors: Yudin Alexey , Enkababian Philippe , Lyapunov Konstantin , Nikitin Alexey , Sitdikov Suleyman , Serdyuk Svetlana , Serdyuk Alexander 
Published: March 2015

Abstract
Channel fracturing technique changes the concept of proppant fracture conductivity generation by enabling hydrocarbons to flow through open channels instead of the proppant pack. The new technique is based on four main components: proppant pulsing at surface with fracturing equipment and software, a special perforation strategy, fibrous material to deliver stable channels, and a set of models to optimize channels geometry.
Channel fracturing in Russia's oil fields began in 2008 as field testing operations in tight collaboration with the development team. Full-suite logs provided geomechanical models and ensured fracture channels optimization. An important result of those first treatments was long-term channels stability. The treated wells continue to show stable productivity over a four-year period. As of today, more than 90 channel fracturing treatments have been pumped in Russia with no screen-outs. A very low screenout risk has become one of the most important advantages of the technology; the fibers make fluid more stable while the presence of clean pulses around proppant structures ensure bridging-free flow. As the channel's conductivity does not depend on proppant size to hold channels open, treatments can be performed with smaller proppants (20/40 or 16/20 mesh) instead of larger proppants (12/18 mesh) that have an increased risk of screenout.
In combination with abrasive jetting perforations, channel fracturing has proven to be an efficient stimulation solution for Russia's multi-layered reservoirs. This completion technique ensures proper flow distribution into perforation clusters according to the channel's specific requirements. It also allows reliable proppant admittance through jetted caverns.
Channel fracturing increases the effective half-length with increased treatment size. A considerable number of channel fracturing jobs with proppant mass equal to standard fracturing designs have been performed—significantly increasing channeled length and providing better production in low permeability (1 to 3 mD) oil reservoirs. Based on production analysis of stimulated wells in five different areas, a correlation between incremental channel fracturing productivity over the conventional stimulation technique and kH value of the formation can be made: the higher the kH the more significant the advantage of the channel fracturing is in oil wells.
Evaluation Techniques of Reserves for Heavy Oil and Oil Sands
Authors: Wensong Huang , Heping Chen , Zheng Meng 
Published: March 2015

Abstract
With the annual growth of development scale and production, the research of heavy oil and oil sands become more and more important. Due to the characteristics of heavy oil and oil sands, the degree of reserves recovery is restricted by development mode. So there is a big difference in classification criterions and evaluation techniques of reserves in the world. In this paper, using the major heavy oil and oil sands accumulation areas —Venezuela heavy oil belt and Canada oil sands as example, we analyse the reservoir characteristic of heavy oil and oil sands, and then discuss the classification and evaluation techniques of reserves suitable for different development modes.
The heavy oil belt in Venezuela and oil sands in Canada are all characterized by huge thickness, middle-fine sandstone, loose cementation, high porosity and high permeability. To adapt different development mode, we establish corresponding evaluation criterions for reservoir, including porosity, permeability, shale content, saturation, barrier and interbed, the thickness and width of continuous oil layer and so on. We classify the reserves as OOIP, economic reserves, reserves for horizontal well, reserves for steam flooding (SF)/ cyclic steam stimulation (CSS) and reserves for SAGD. Using logging and geophysical techniques, we evaluate and classify the reserves.

1.Introduction
Heavy oil and oil sands are characterized by shallow buried depth, large thickness, huge reserves and unconsolidated structures. Because crude oil has high viscosity, conventional vertical wells generally have no or extremely low productivity. Currently, these reservoirs are predominantly developed by horizontal wells in two stages: cold production and thermal production. All these conditions have presented new requirements on contents and methods of reserve evaluation. In this essay, through study on reservoir features and corresponding development techniques for heavy oil in Venezuela and oil sands in Canada, we put forward reserve assessment methods and techniques by class for various development modes.

2.Reservoir evaluation and selection criteria for heavy oil and oil sands development
Currently, cold production (CP) is the prevailing development method adopted for heavy oil in Venezuela, at the same time, cyclic steam stimulation (CSS), steam flooding (SF) and SAGD have been tested. Oil sands in Canada are mostly developed by SAGD and open mining. A series of reservoir selection criteria have been proposed to cope with requirements of different development methods with horizontal wells on oil layers (Table 1).
A Meshless Surface-Fitting Method for Fault Detection
Authors: BaDughaish F.A. 
Published: March 2015

Abstract
Seismic data adequately reveal subsurface geological structures but require special analysis techniques to detect subtle geological features such as faults. Detection of faults in seismic data is, for the most part, a qualitative procedure requiring proper data interpretation, sometimes leading to a source of ambiguity for the real fault location. Quantitative techniques based on seismic attribute analysis are employed to reduce this ambiguity and are the focus of this study.
A new numeric method based on the meshless Moving Least Squares (MLS) is used to enhance the fault detection technique introduced by Gibson et al. (IEEE 43:2094–2102, 2005). This method generates a set of points called seed points, which lie on the fault surface, by examining the eigenvalues (i.e. the local covariance matrices of the structural tensor) of cubes from the data. Next, the seed points are grouped together using the neighborhood relationship (compatibility) between every two individual points. Finally, the seed points are used to create the final surface. A meshless technique is then used to fit a surface through these points. Fitting the meshless surface is found to be more efficient than traditional mesh-based techniques.
This study also compares various mesh-based and meshless techniques. It is found that meshless methods have better accuracy, are more efficient in determining point connectivity on-the-fly at run-time, and avoid mesh-alignment issues. Also, traditional surface fitting techniques divide the fault surfaces into smaller surfaces (a common problem called over-segmentation), which is less of a problem using meshless methods.
The MLS-based meshless surface fitting approach has shown promising results with potential benefits to seismic data interpretation and geological structure delineation. This method has not yet been adopted in the oil industry. However, the results have shown great potential for improving the quality of seismic interpretation in general and fault detection in particular.
Successful Fracture Stimulation in the First Joint Appraisal Shale Gas Project in China
Authors: Jin Liang , Zhu Changlong , Ouyang Yong , Zhou Ming , Qu Qingguang , Li Fei , Yuan Roger , Wu Chris , Zhang Zhiyi , Wang Yan , Dwan Fa , Vitthal Sanjay , Wang Shiqian 
Published: March 2015

Abstract
This paper discusses fracture stimulation in the first joint venture shale gas project with foreign companies in China. Shell China Exploration and Production Company (SCEPCO) is jointly appraising the shale gas play with partner PetroChina. The block is in Sichuan, China. The target zone is Longmaxi hot shale, a Silurian formation. Its matrix permeability is extremely low, in the range of 100–300 nano-Darcy but rich in natural fractures. Hydraulic fracturing has been proven a key to enhance the production by effectively connecting natural fractures and providing a path for the gas to flow into the wellbore.
"Every shale reservoir is different." The joint working team is facing specific challenges in this play:Understanding of reservoir based on the study of geology, petrophysic, geomechanics.High wellhead treating pressure due to high formation stress and pore pressure.Deep wells - some deeper than 3,500m TVD.Fluid system and proppant type and size selection.Fit for purpose treatment size and pump program.Connection between wellbore and formation through the fracture.Horizontal wells - Stimulation interval selection, stage spacing, perforating strategy.Unknown fracture geometry - only 1 microseismic was applied in a horizontal well.
Two vertical wells and three horizontal wells have been fracture-stimulated to date. The team has gained valuable experience and made significant improvement step-by-step and well-by-well. This paper discusses how a collaborative approach was applied to the completion of the shale gas wells during appraisal. Initial production test results of the wells have been promising. This is a significant step to unlock the potential of shale gas resources in China and help meet the country's energy needs.
Marine Seismic Acquisition at Scott Reef, Western Australia: Minimising Environmental Impacts in a Sensitive and Remote Location
Authors: Taylor Mark , FitzPatrick Jeremy , Weiss Ralph 
Published: March 2015

Introduction
The Torosa gas field forms part of the proposed Browse LNG Development1, a project to commercialise three gas and condensate fields located on the outer continental shelf of northwest Australia, approximately 400km north of Broome. Two of these fields (the Brecknock and Calliance fields) are located in deep water and have been fully imaged by modern 3D towed streamer seismic surveys. However, the Torosa field partly underlies Scott Reef, which consists of two coral atolls separated by a deep channel.
The only permanently emergent land at Scott Reef is a small sand cay (Sandy Islet - Figure 1), although the reef crests of both atolls are exposed at low tide. Outside the reefs the seafloor drops away rapidly, with water depths of about 350m to the east, increasing to more than 1000m to the west. South Scott Reef lagoon is open to the north, with water depths increasing to about 50m before deepening abruptly into the channel between the two reefs. North Scott Reef lagoon is shallower - generally less than 25m - and is connected to the ocean by two narrow channels. Semi-diurnal tides with a range of up to 4.6m produce strong tidal currents in and near these channels. Small, steep-sided coral heads, or 'bommies', are common throughout the lagoons, especially in water less than 25m deep.
Since 2005 Woodside Energy Ltd has acquired five seismic surveys over the Torosa field using a range of acquisition techniques. These surveys were important steps towards acquiring full seismic coverage over the Torosa gas field (Figure 1). The first of these surveys, the Torosa 3D marine seismic survey (MSS), was a conventional deep water 3D towed streamer marine seismic survey acquired in late 2005, which covered the deep water portion of the Torosa Field located northeast of Scott Reef. Four further seismic surveys have extended the area of 3D seismic coverage into the south Scott Reef lagoon and across north Scott Reef.
Prior to commencing the seismic programme over the shallow-water parts of the Torosa Field, Woodside carried out an extensive airborne bathymetric survey of the entire Scott Reef system in early 2006. Additional bathymetric surveying was undertaken to fill some data gaps within the airborne bathymetry survey, resulting in a comprehensive, highly-detailed data set on a 4m2 grid with vertical resolution of 0.1m covering both north and south Scott Reef to depths of about 50m. Woodside also undertook extensive metocean work including both tide and current modelling and model verification. These datasets were critical for the planning of the subsequent seismic surveys.
Effective Well Integrity Management in a Mature Sour Oil Field
Authors: Almukhaitah Abdulaziz A. , Haldar Surajit 
Published: March 2015

Abstract
Maximizing the productive life of wells and minimizing the risk of uncontrolled release of reservoir fluid over the entire life cycle of the wells are the major objectives of any E&P company. Therefore, managing well integrity has become as important as managing reservoirs without compromising the safety of personnel or the harmony of the environment, and at the same time protecting valuable assets for a prolonged life.
One of the large mature onshore oil fields of Saudi Arabia is producing sour crude oil that multiplies the well integrity challenges. A stringent well integrity surveillance and maintenance program is followed for this field to ensure the integrity of every individual well. The program, essentially developed for Saudi Aramco onshore oil fields, is a proactive problem prevention-based approach. Under this program, any well integrity related problem can be predicted through a structured preventive diagnosis and maintenance schedule for both wellhead and downhole integrity to assure well integrity that verifies and confirms the status of wells with suspect integrity. The program is governed by the operating standards and guidelines for maintaining the well integrity parameters, ensuring safe well operations and securing uninterrupted well productivity and injectivity. The program also emphasizes the requirement of barriers during normal operations, unscheduled well interventions or when shut-in for safety and environment protection.
This paper describes the process for efficiently managing well integrity throughout the development life cycle with a particular focus on production operations and the well maintenance phase. The objective of this paper is to provide an overview of the rationale for following this structured program and the realized benefits.
Fluid-Level Monitoring Using a Distributed Temperature Sensing System During a Methane Hydrate Production Test
Authors: Sakiyama N. , Fujii K. , Pimenov V. , Parshin A. , Yamamoto K. , Wright J.F. 
Published: March 2015

Abstract
Temperature profiles and their transient behaviors obtained using a distributed temperature sensing (DTS) system were measured while monitoring wellbore fluid levels during a methane hydrate production test. The temperature data were obtained in 2008 as part of the JOGMEC/NRCan/Aurora Mallik 2007–2008 Gas Hydrate Production Research Well Program.
Methane hydrate is known to be stabilized under low-temperature and high-pressure conditions. In the Gas Hydrate Production Research Well Program, a depressurization method using an electric submergible pump (ESP) was employed to dissociate the hydrate in the reservoir. For recovering the produced gas and fluid without resynthesizing the hydrate after the dissociation, it was essential that the temperature of the produced fluids flowing up the tubing be controlled.
According to our numerical temperature simulation, the annulus fluid level around the tubing is one of important factors that govern the tubing fluid temperature during the methane hydrate production. If the annulus fluid level is high, the tubing fluid temperature becomes so low that methane hydrate can potentially be formed inside the tubing; thus, understanding fluid levels during methane hydrate production is important for flow assurance as well as bottomhole pressure control. The conventional method for estimating fluid levels in a wellbore employs an acoustic wave reflection technique; however, the accuracy of the survey is subjected to assumption of an acoustic velocity which depends on pressure, temperature, and gas types. On the other hand, estimating fluid levels with a DTS temperature profile is thought to be a more direct method. Although it is not widely known, several papers indicate that the feasibility of estimating fluid levels with the DTS system when the fluid level is static.
In this paper, we demonstrate the feasibility of estimating dynamic fluid levels using a DTS system. The dynamic trend in estimated fluid levels with the DTS system shows qualitatively good agreement to that estimated with the pressure on the completion assembly and the pressure at the casinghead. The difference in fluid levels between the DTS temperature-based and the pressure-based methods quantitatively explains a void fraction in the two-phase flow of the fluid and the gas. The analysis presented in this paper is based on field data collected during methane hydrate production, but it is potentially applicable to any conventional production scheme that employs artificial lift.
An Integrated Approach of Sequence Stratigraphic Study in Southwestern of Malay Basin
Authors: Wei Chen Harry Wong , Ab. Aziz Sham Shukriah , B Mahmud Othman Ali , Pendkar Narender , Bt Sapri Dayang Haspariah 
Published: March 2015

Abstract
This paper presents the results of an integrated sequence stratigraphy approach using seismic, well log and biostratigraphic data to build sequence stratigraphic framework and its implication in petroleum system understanding for the southwestern part of the Malay Basin. Seismic data were used to interpret third order Sequence Boundaries (SB) and Maximum Flooding Surfaces (MFS) based on reflector terminations. Well log analyses were carried out to support the interpretations and were cascaded down to define the third order sequences and associated system tracts (LST, TST and HST). Biostratigraphic data were also used to validate the SB, MFS and the paleo-environments.
This study has subdivided the sedimentary successions into six 3rd order sequences namely Sequence 1 to Sequence 6. Each of the sequence is bounded by sequence boundary, which has been calibrated with the Malay Basin Chronostratigraphic Chart (PETRONAS, 2007).
Two source rocks are present for the study area- the deeper synrift section with source rocks deposited in a lacustrine environment (Late Oligocene age) and the shallower source rock deposited in a marine inner neritic environment (Early Miocene age). The migration pathway for the deeper section is through faults, and from lateral migration for the shallow section. The study also indicates that the potential reservoirs are thinning basinward (southwest to northeast). The potential reservoirs are interpreted to be the fluvial, lacustrine and shallow marine sands. Data from several key drilled wells suggests that reservoir is at low risk in the sand-prone areas of the southeastern part compared to the northern part which is more shale-prone. Based on the present study, it is inferred that trap integrity is the main risk for petroleum system. While a good top seal is provided by the main regional shales in deeper section, the seal at the shallow sections are from thin and discontinuous intra-formational shales that are present in every sequence. The presence of younger faults cutting through the reservoir may cause the potential for hydrocarbon leakage.
The present study has identified five potential plays and also established the regional sequence stratigraphic framework in southwestern of Malay Basin.
Use of Chemical Foamers to Deliquify the Loaded Wells in Sebei Gasfield
Authors: Zhi-jian Liu , Chunming Xiong , Wenkui Li , Jun Li 
Published: March 2015

Abstract
In Sebei Gasfield, liquid loading in the well bottom has seriously impacted the well productivity. Use of chemical foamers to deliquify the loaded wells has testified to be one of the most effective mothods. However, it is always challenging work to select the most compatible foamer. Besides, not all wells will respond successfully to the foamer treatment. Thus, tedious work has to be done to screen the potential wells. In this paper, a novel efficient foamer has been developed using the Response Surface Method. It provides a new way to formulate foamers for gas well deliquification. It proves both time and labor saving. Using historical well data and from discussion with the operator, an understanding of the candidate wells can be gained. The criteria for selecting a ideal candidate well for foamed lift has been fully investigated. We find the most suitable flow regimes for foamer treatment are slug flow and annular flow. Then, we optimize the usage of foamer with the aid of mathematic model. The foamer injection pattern, such as intermittent injection and continuous injection, has also been discussed. For different well condition, different injection pattern should be applied. This paper also includes several field trial cases.