bluuebunny/crossref_metadata_2025_split huggingface dataset:
Two Years Down the Road in Production with Downhole Flow Control Solution in SS Field, Offshore East Malaysia - Success Case Studies, Lesson-Learnt and Way Forwards
Authors: Noridah N. , Saiful M.M. , Anuar M.Y. Saiful , Nur Hazrina K.Z. , Hayat N. Zadil , Gordon Goh K.F. 
Published: May 2016

Abstract
Developed amidst some of the most challenging offset brown fields in the S clusters offshore East Malaysia, SS field has undergone a rigorous drilling and completions campaign extending from Q4-2009 to Q1-2011(i.e. 15 months). 14 wells with downhole flow control solution plus 3 water injectors for long-term pressure maintenance were planned. A campaign of 12 'passive' Inflow Control Devices, ICD's wells and 2 'active' cost-effective surface-controllable intelligent wells was executed with success.
All wells are horizontal to optimize well counts in penetrating more layers and drainage across entire reservoir of approximate 40m thick oil column. However as predicted in the dynamic reservoir modeling, under the huge threat of a large and expanding gas cap (i.e. m size of 2) coupled with the underlying moderate aquifer strength of imposing water encroachment; all the wells, if completed without downhole flow control, will get early gas and/or water breakthrough in a matters of days/months with huge oil bypassed. Hence, the notions of smart and/or advance completions for downhole inflow control solution are to promote this field development into solving the predicted sub-optimal production in order to achieve the target recovery factor of at least 30% in this challenging multi-stalked, very heterogeneous and highly-dipping reservoir.
In this paper, all the twelve (12) ICD's wells plus the two (2) intelligent wells post-execution production analysis will be discussed. A post-mortem of the effectiveness of such innovative solution is performed to assess the production impact on SS field with some wells' production data available more than two years'. From the good success case studies of the high-performance wells, post-production profiles have indicated a huge transformation towards realising more oil incremental while reducing the cost of handling less water and gas. However, lesson-learnt can also be drawn from a few of the so-called "Could-have-been-better-performers". This is then highlighted with the way forwards plan to both further sustain production and look-ahead into applying the best practices of such technology pilots to other asset development and conceptual. This paper could provide an eye-opening insight into some of the best-kept value of downhole flow control application with actual production impact and data analysis.
Mechanisms of Generating Overpressure and Its Influences on Super-Low Permeability Reservoirs of Upper Es4 Member, Chexi Depression
Authors: Zhenyu Zhao , Yanru Guo , Qing Zhang , Hong Liu 
Published: May 2016

Abstract
By means of analyzing super-low permeability reservoir of upper Es4 member in Chexi depression into sedimentary microfacies, diagenesis, reservoir porosity and permeability and testing geochemical data, the mechanisms of generating overpressure and its influences were discussed. The results show that:The reservoir, being evaluated medium-low porosity and super-low permeability, is disadvantageous to oil & gas exploration and development, as lithology is argillaceous fine sand, porosity is 10% ~ 20% and permeability is less than 10×10-3µm2 in general;The principal mechanism of generating overpressure is disequilibrium compaction, and the secondary is mineral diagenesis;The overpressure can effectively inhibited formation temperature to increase and diagenesis process;In overpressure wells section, the secondary porosities and fractures are preserved during mesodiagenesis stage and telodiagenesis stage, which are favorable to oil and gas exploration and development;In study area, it is not a positive linear relationship between oil production capacity and formation pressure coefficient, as high production capacity corresponds to the pressure coefficient of 1.2~1.3.
With increasing production capacity of the global oil and gas and exploring most oil and gas reservoirs year by year, the influencing factors of super-low permeability reservoirs was also more and more attention [1–3]. Since the 1950s, through the geologic simulations and the typical overpressure basin studies, many scholars analyzed that overpressure could preserve the primary and secondary porosity to improve reservoir preformation in two kinds of mechanisms with physical and biochemical actions [4–6]. In development process of overpressure reservoirs, the overpressure fluid will change rock stress to make the elastic and plastic deformation, so as to reduce the porosity and permeability [7–8]. Therefore, overpressure constructive and devastating effects on reservoir properties still need further clarification.
Creating Economic Value from Porosity and Permeability: Integrating Geology, Reservoir Engineering and Commercial Factors for Evaluation of Unconventional Resource Opportunities
Authors: Steffen Kurt , Hood Ken 
Published: May 2016

Abstract:
Comprehensive evaluation of unconventional resource opportunities requires the integration of geologic, engineering, timing, competition, and fiscal factors that influence the commerciality of a project. Although unconventional resources such as Shale Gas, Tight Gas, Tight Oil, and Coal Bed Methane commonly are treated as continuous accumulations, the subsurface and operational considerations that control commerciality vary spatially throughout the play. Evaluation of these resources requires an approach that honors the "continuously varying" nature of the hydrocarbon accumulations. Unconventional resources, particularly natural gas, can have significant influence on local markets. Such effects can challenge areas within plays that have less favorable geologic quality, operational challenges, or costs. As a result, early identification of the geologic sweet spot and optimal project required to exploit the resource is crucial.
Wulalike-Kelimoli Petroleum System of the West Margin of Ordos Basin, China
Authors: Xu W. , Guo Y. , Liu J. , Gao J. , Zhao Z. 
Published: May 2016

Abstract
The Ordos Basin, which is situated in the north part of China, is one of the largest basins in terms of natural gas resources in China. Natural gas accumulation from marine source rocks in Ordovician was found recently in the west margin of Ordos basin. The purpose of this paper is to describe the geological conditions of gas accumulation in the Ordovician in the west margin of Ordos basin and the identification of the Petroleum System.
The marine source rocks, occurred in the Kelimoli and Wulalike formations of Ordovician which consist of shale, mudstone and marlstone, are mainly distributed in the west margin of Ordos basin where sedimentary environments are deep ramp faces. The thickness of strata ranges from 20m to 200m, with the TOC ranges from 0.19% to 4.55%. The kerogens are dominated by type I or II and the thermal maturity is mostly in the range of 1.4 to 2.8% Ro.
Limestone bedding karst cavity reservoir in Kelimoli formation constituted the main space for the gas accumulation. The bedding karst cavity reservoir, with the average porosity between 4% to 6% and the permeability between 0.1×10-3µm2 and 2.0×10-3µm2, is the main gas reservoir. The limestone bedding karst cavity reservoir mainly distributed in the west with the thickness between 60m and 170m and is interbedded with the source rock while the dolomite reservoir mainly distributed in the east.
The overlying coal-bearing strata which are wide continuous distributed prepared the good cap rock with high quality. The Kelimoli limestone is the main reservoir rock. The Wulalike mudstone is not only the source rock but also good local cap rock. The overburden rock includes the late Carboniferous, Permian and all the Mesozoic and Cenozoic. Lithology lateral change in Kelimoli formation is the main reasons to control the traps, and structure movements are the minor reasons for traps. The vitrinite reflectance values and the homogenization temperature of fluid inclusions suggest that the onset of the oil generation started in the late Jurassic and gas in the early Cretaceous.
A New Analytical Model to Predict Gas Rate Volume Measurement Through Well Head Chokes
Authors: Leal Jairo , Al-Dammen Mohammed , Villegas Ruben , Bolarinwa Simeon , Aziz Abdul , Azly Ahmad , Buali Mustafa , Garzon Francisco 
Published: May 2016

Abstract
Historically, choke gas equations have been extensively used for gross estimation about gas volumes. These analytical models give a quick evaluation on gas volume but also face some serious limitations on specific topics like water presence, excessive gas velocity and pressure drop, limited differential pressure and high condensate to gas ratios. Many different efforts have being completed using several analytical models which can be applicable under certain conditions.
This paper details a new predictive model for estimating the gas rate measurement through wellhead chokes and also covers all efforts for Saudi Aramco to get a single digit error on estimating gas rates for Ghawar gas condensate producers by implementing this new analytical model.
Additionaly, the application of this new gas equation covers a wide range of operative conditions as well as gives great benefits since perspective of:Reducing gas allocation errorImproving gas estimation while comparing with regular test separatorIdentifying well optimization opportunitiesGetting cost saving while minimizing use of conventional well-testingValidating venturi meter calculationsImproving well performance and diagnosticKeeping surface equipment under optimum operative conditionsMinimizing erosion while providing optimum gas velocity calculations
The main objective of this paper is sharing this equation with Gas Producing Engineering Worldwide community and covering methodology of implementation as well as sharing practical field application cases.
Productivity Decline Due to Fines Migration (Modelling and Field Case)
Authors: You Z. , Badalyan A. , Bedrikovetsky P. , Hand M. , Jenson D. 
Published: May 2016

Abstract
High formation damage, including that induced by fines migration has been reported in numerous geothermal projects. The attaching electrostatic forces acting on fines are weak at high temperatures if compared with drag and lifting forces, which detach the particles from grain surfaces. Migration of lifted fines results in their straining in thin pores preferentially near to well, causing severe permeability and productivity decline. A mathematical model has been developed, based on recently developed theory of particle detachment in suspension flows. Solution for predicting well productivity is obtained. The model is validated by comparison with the field data from geothermal well A in Australia. Productivity decline due to fines migration is more likely to happen in high temperature geothermal reservoirs if compared with conventional aquifers or oil and gas fields.

Introduction
Productivity decline as well as induced formation damage due to fines migration in conventional oil and gas reservoirs has been widely reported since 1960s, and is still a hot topic these days (Muecke, 1979; Lever and Dawe, 1984; Sharma and Yortsos, 1987; Sarkar and Sharma, 1990; Khilar and Fogler, 1998; Tiab and Donaldson, 2004; Civan, 2007; Geng et al., 2010; Rosenbrand et al., 2012). The phenomena including fines mobilisation, subsequent reduction of reservoir permeability and formation damage have also been observed during drilling, discharge, injection and production stages in the geothermal wells. However, the comprehensive analysis of formation damage specific for geothermal reservoirs is not available yet.
Flow of suspended fine particles with particle capture, detachment and rock clogging takes place in porous media (Fig. 1), during the propagation of particles, bacteria and oil droplets in reservoirs, filtrate invasion into formation while drilling, injection and discharge of water in geothermal fields, etc. The particles at the rock surfaces are subject to the electrostatic force Fe, drag force Fd, lifting force Fl and gravitational force Fg (Fig. 1). The drag and lifting forces tend to detach the particle from the grain surface while the electrostatic and gravitational forces attach it. It is assumed that at the moment of leaving the solid surface, the particle rotates around the neighbouring attached particles or around a spike of the surface ((Fig. 1b,c). Therefore, the condition of mechanical equilibrium of a particle on the grain surface is the balance of the detaching and attaching torques exerting on the particle (Freitas and Sharma, 2001; Bedrikovetsky et al., 2012). At high flow velocity near the wellbore, the detaching torque on the particles may exceed the attaching torque. Thus, the particles can be released and brought to the suspension flow as a result. The migrating particles may be further captured at thinner pore throat, or attached to the pore wall (Fig. 2), depending on the particle and pore geometry and hydrodynamic conditions.
Explicit Modeling of Hydraulic Fracture Propagation in Fractured Shales
Authors: Savitski A.A. , Lin M. , Riahi A. , Damjanac B. , Nagel N.B. 
Published: May 2016

Abstract
Recently a combined application of two technologies, horizontal drilling and multi-stage massive hydraulic fracturing (HF) has made vast resources of shale gas commercially viable. The HF is a well-established reservoir stimulation technique, which has been developed over the last half century. There are reliable tools for designing HF in conventional reservoirs, in which a planar HF is assumed.
On the contrary, in shale gas fracturing, micro-seismic observations have illuminated a complex internal structure resulting from the interaction of the induced hydraulic fractures with natural fractures. It is widely speculated that the stimulated natural fractures make a significant contribution to the gas production.
The mechanics of the interaction between multiple fractures during a HF treatment is very complicated. In this paper we present the results of state-of-the-art modeling of an explicit interaction between a propagating hydraulic fracture and a statistically generated discrete fracture network. A sensitivity study reveals a number of interesting observations including importance of initial fracture conductivity for growth of the fracture system, effect of the dilation angle on the generated conductivity and net pressure and uneven distribution of fracture aperture that is critical for proppant placement.
This work strongly links the production technology and geomechanics and suggests an approach for modeling and designing HF treatments in unconventional shale gas plays.

Introduction
Natural gas and light oil production from shale formations has become the focus of much attention in the past decade. The economic success of the development of these unconventional resources owes to a combined application of two key and well-known technologies: horizontal drilling and multi-stage hydraulic fracturing (King, 2010). The horizontal wellbore sections, commonly with length ranging from 750 m to over 1600 m, are either cased and cemented or isolated with packers to enable multi-stage fracture stimulation (Cipolla, 2009). Hydraulic fracturing (HF) is a well-established reservoir stimulation technique, which has been developed over the last half century. It is not an exaggeration to say that in ultra-tight reservoirs such as shales the connected reservoir conductivity is created in the process of hydraulic fracturing and that enables any measurable hydrocarbon production.
Modeling and Performance Interpretation of Flowing Gas Composition Changes in Shale Gas Wells with Complex Fractures
Authors: Freeman C.M. , Moridis G.J. , Blasingame T.A. 
Published: May 2016

Abstract
Limited attempts have been made to model shale gas reservoirs on a compositional basis. Multiple distinct physical phenomena influence the behavior of reservoir fluids in shale, resulting in measurable compositional changes in the produced gas over time. These phenomena include differential desorption, fractionation via phase change, and preferential diffusion. To address these phenomena, we have developed a compositional numerical model which describes the coupled processes of diffusion and desorption. We have also developed a tool for generating simulation grids capturing fracture geometries of realistic complexity. By combining the physics of flow in complex fractures with diffusion through nanopores, we show how gas composition changes during production. We identify and illustrate signature trends in the flowing gas composition according to our model. In addition, we present a workflow for the integration of measured gas composition data into traditional production data analysis. We prove that the onset of various transient flow regimes that are unique to shale gas reservoir systems can be identified in the model-based flowing composition data. For example, the transition from fracture-drainage to matrix-drainage can be identified by a characteristic trend in flowing gas composition. Some reservoir properties can be determined through analysis of the compositional shift in the flowing gas. This work expands the current understanding of well performance for shale gas to include physical phenomena that lead to compositional changes for realistic fracture configurations. This work can be used to optimize fracture and completion design, improve well performance analysis and provide more accurate reserves estimation. In this work we develop a numerical model which captures multicomponent desorption, diffusion, and phase behavior in ultra-tight rocks, we present a grid generation technique which captures the complexity of shale system fractures, and we validation of our interpretations of diagnostic trends.
Operational Challenges in Managing High CO2 Content Gas Production in Peninsular Malaysia Operations
Authors: Hadi Sriyanta , Meri Ambok Malek , Mahadi Ahamd Zulhairi , Abd Ghafar Ezatul Shima , Shariff Din Siti Nurul Aimi , I Fen Soh 
Published: May 2016

Abstract
Peninsular Malaysia Operations (PMO) plays an important role in supplying gas demand throughout the region since the gas business commencement in 1980's. Currently about 600 MMscfd gas is supplied by PMO. At the moment, three non-associated gas (NAG) fields, namely DYG, RSK, and TBC contribute to about 50% of the total gas supply from PMO. Apart from producing NAG, the RSK and DYG fields also serve as network hubs to evacuate gas to the Onshore Gas Terminal (OGT) through two independent gas delivery systems: Joint Delivery System (JDS) and Resak Delivery System (RDS) respectively. The two JDS and RDS gas streams are mixed at OGT and then delivered to the customer processing plant, with a CO2 maximum limit of 8% by mole. Apart from the many operational challenges to sustain gas production, meeting the gas specification proves to be a difficult task, especially for the RDS where TBC gas (with about 30–40% CO2) is to be blended with RSK gas (itself producing about 23% CO2).The TBC gas was put on stream in 2011 and an Acid Gas Removal System (AGRS) was deployed to reduce CO2 content. Prior and upon commissioning of the AGRS facility, feed of CO2 level into the gas network was managed by optimizing the flow rate. This paper describes some major challenges in sustaining the gas production supply and meeting the gas quality requirement. The major operational challenges include subsurface uncertainty and problems, maintaining gas compression reliability, AGRS operations and optimizing the usage of gas pipeline network. To complete the analysis, some commercial aspects are also discussed in the paper.

Introduction
This section consists of two parts:overview of gas business in Peninsular Malaysia andoverview on RSK/DYG field operations.
The first part would be introducing the gas market in Peninsular as well as the strategy of fulfilling the gas demand. The second part would be describing the RSK/DYG field operations as the focus of this paper.
An Integrated Approach to Phase-Wise Marginal Fields Cluster Development - A Case Study of C Series Offshore Fields, India
Authors: Vasudeva Sudhir , Nischal Rajiv , Kumar Adesh 
Published: May 2016

Abstract
The C-Series fields are mainly gas bearing with marginal reserves distributed in multiple pays and spread over a large area. They are located in the Arabian Sea, far away from existing infrastructure, in shallow water depth (24–30m), having very high under currents and adverse weather conditions. As independent development was not viable, concerted efforts involving integration of human resources, advanced technologies improving scale of economies by cluster development and changed economic scenario, these fields could be made economically feasible.
The paper brings out how development has been undertaken using new concept and technologies in a phased manner to reduce capital cost of platforms, pipeline & processing facilities to maintain plateau rate for a few years. This paper discusses multidisciplinary task based parallel working with real time integration of results and midcourse corrections while formulating fast track phased development plan. The functional tasks included geological modeling, reservoir simulation, innovative well drilling and well design, assessment and adequacy of existing and nearby facilities and pipelines to minimize offshore development cost, simulation of fluid flow dynamics for both wells and pipelines for various operating conditions, well design & drilling options, well completion, selection of material, equipments and facilities. Besides setbacks in some fields, substantial upward revision of gas in place has been established in other area and it has been decided to advance the later phase development for early monetization of upside reserve using an old rig to be converted as MOPU for phase segregation and compression. This paper also discusses brief details of the selected options while presenting this classic case of this challenging offshore cluster development.

Introduction
Many small & marginal fields have been discovered in western offshore, India and C-Series is one of them. The C-Series small & marginal fields comprises of fields, namely C-22, C-23, C-24, C-26, C-39-1/3, C-39-6/8, and B-12 Structures. These fields [1] lie in a NE- SW alignment spread over a distance of 110 Km, situated in Tapti Daman block of Mumbai Offshore Basin. They are in Tapti-Daman area of western offshore in Arabian Sea at about 160 to 200 Km from the city of Mumbai and about 60 Km west of city of Daman. These are mainly gas bearing with reserves distributed in multiple pays and spread over a large area. The farthest field is located about 180 Km away from existing Mumbai High North Platform (NQ). These fields lie in a roughly NE-SW alignment, spread over a distance of 110 Km, and are mainly gas bearing in Daman and Mahuva formations. These fields are in shallow water depth (24–30m) having very high under currents and adverse weather conditions.