bluuebunny/crossref_metadata_2025_split huggingface dataset:
Seismic Guided Drilling: Near Real Time 3D Updating of Subsurface Images and Pore Pressure Model
Authors: Peng Chuck , Dai John , Yang Sherman 
Published: May 2016

Abstract
Seismic guided drilling (SGD) is a workflow that uses drilling information from a well being drilled and existing surface seismic data plus offset well information, to recalibrate and update the existing 3D earth model, including seismic image, pore pressure, fracture gradient, and geological hazards in order to reduce drilling uncertainty and mitigate drilling risk ahead of bit.
The modern practices in drilling heavily rely on the predrill earth models. The predrill models often are not precise due to the inherent non-uniqueness in our remote sensing techniques. While LWD/SWD and WL provide useful information along the borehole, they offer little understanding about the rock property ahead of bit. SGD is such a technology that constantly improves the 3D earth model ahead of the bit through the integration of current well measurements with existing surface seismic data, with a turnaround time on the order of 24hours. It not only corrects the model error behind the bit but also improve predictions ahead of the bit.
The lack of adequate technologies, measurements, and turnaround time limitations, has made this type of optimum utilization/integration of seismic data and well data impractical until now. Recent developments in model building, rapid and accurate imaging technologies, and the availability of new well measurements, aided with modern engineering and computation, have made this optimum combination a reality. SGD has been used in several high-profile deep water HPHT wells worldwide with considerable successes. The technology is especially valuable in areas of low exploration activity or high geological complexity.
The paper focuses on illustrating the concept of SGD technology and presenting a field example in the Gulf of Mexico, USA.
Determining Coefficient of Quadratic Term in Forchheimer Equation
Authors: Ling Kegang , He Jun , Wu Xingru , Shen Zheng 
Published: May 2016

Abstract
Forchheimer equation takes non-Darcy flow effect into account in the event of high flow velocity in porous media. Its application requires both permeability, which is in linear term, and Beta factor, which is in quadratic term. Permeability and Beta factor are determined by rock type, textural of rock, effective porosity, pore throat size, geometry of the pore, and connection and distribution of pores. Beta factor comes into play when the fluid flow rate is high and the flow rate deviates from Darcy's law. Non-Darcy flow is described by Forchheimer equation. Usually the coefficient of non-Darcy flow term is hard to be determined. Existing approaches are core measurement and empirical correlations. To the best of our knowledge there is notheoretical equation available. To get an accurate estimation of flow rate or pressure drop in the reservoir, we need a method that has solid theoretical basis. The deficiency triggered our study.
Starting from multiple-capillary tubes concept, we derived a rigorous relationship between pores geometry and pressure drop required for fluid flow through the pores. Through this correlation pressure drop can be calculated from known pores geometry. Since pores geometry can be often obtained from lab experiment or well logging, the new correlation also provides a unique approach to quantify the coefficient of quadratic term in Forchheimer equation.
In this study we developed a governing equation through a rigorous theoretical derivation. With this equation the non-Darcy flow coefficient in Forchheimer equation can be calculated. The required input data for the new equation are readily obtained from well log interpretation. The new equation is a powerful tool in the event of no experimental measured non-Darcy flow coefficient available. It eliminates the errors or the arbitrary content in the empirical correlations.
Integrating an LNG Plant with an Unconventional Gas Supply
Authors: Langley Chris , Spaander Adriaan 
Published: May 2016

Abstract
Arrow Energy is a JV company based in Brisbane, Australia, that is owned50/50 by the Shell group and PetroChina (a subsidiary of CNPC). Arrow is planning to develop its tenement holdings of Coal Seam Gas (CSG) in the Surat and Bowen Basins of central Queensland. The CSG will be produced at very low pressures from shallow wells, gathered and compressed into two 500 km trunk-lines for delivery to a two train LNG plant, with each train sized at 4.0mtpa capacity. The LNG plant will be located on Curtis Island, opposite Gladstone harbour, in Queensland.
CSG is classed as "unconventional" gas; this is the first time that Shell or PetroChina have designed an LNG plant with an unconventional gas feed. The paper discusses the unique aspects of integrating an LNG plant with this unconventional gas feed.
The main topics covered in this paper are:Implications of CSG composition for LNG plant design,Implications of CSG ramp-up for LNG plant design,Optimising the Availability of the Integrated system, and,The use of novel design and new technology approaches in the LNG plant in order to reduce costs.
Hydraulic Fracturing Candidate-Well Selection by Interval Type-2 Fuzzy Set and System
Authors: Zoveidavianpoor Mansoor , Samsuri Ariffin , Shadizadeh Seyed Reza 
Published: May 2016

Abstract
Selecting a target formation(s) among a vast numbers of zones/sub-layers within huge numbers of hydrocarbon producing wells in a reservoir, is considered a difficult task, particularly if the selection goes through a group of parameters having different attributes and features; such as geological aspect, reservoir and fluid characteristics, etc. The trend of candidate-well selection (CWS) process for Hydraulic Fracturing (HF) had recognized to be complex, nonlinear, un-equilibrium, and adherent with uncertainty. Interval Type-2 Fuzzy Logic and Systems (IT2-FLSs) are very useful in circumstances where it is difficult to determine an exact membership function (MF) for a Fuzzy Set (FS); hence they are very effective for dealing with uncertainties. Classical FLS which called T1-FLS is not capable of fully capturing the linguistic and numerical uncertainties in the terms used and the inconsistency of the expert's decision-making. Therefore, the need arises to use a method that could handle uncertainties. The procedure of applying this novel study in the area of HF CWS, will have illustrated through a case study in a carbonate reservoir. The utilization of a modern and right problem-solving tool such as T2-FSS should be considered a great concern to the petroleum industry. Although sizeable clarity has been achieved in this area, no conceptualization such as dealing with uncertainty, has yet answered by the previous studies. New requirements force the previous methods to advance and novel techniques expected to meet the requirements and remove the existing weakness. In highlighting this need, the question has been answered about why IT2-FLSs should be used in this study. Also, its advantages over T1-FLS will be illustrated. This paper critically assesses the importance of the proposed methodology to develop a reliable model of HF CWS. This investigation is the first research which applied such a cutting-edge approach and tries to fill the gap between recent developments in uncertainty management through utilization of IT2-FLSs in HF candidate-well selection.
Drilling of Multilateral Wells Aided with Geochemical Analysis
Authors: EL Gezeeri Taher , Ismail Abdul Aziz , Al-Anezi Khalaf , Al Jeaan Monirah , Silambuchlvan Jeevan Kumar , Padhy G.S. , Wasnik Atul , Al Shoeibi Ahmed 
Published: May 2016

Abstract
This paper describes the utilization of Real-Time geochemical analysis to support geosteering of a smart multi-lateral well, located in one of the highest flow potential areas in Kuwait. The Burgan reservoir consists of vertically stacked channel sands along with a fault network connected to the aquifer and contains highly viscous reservoir fluid. This drastically enhances the water mobility, and results in severe premature water breakthrough. Hence, leaves zones of by-passed oil. For optimum reservoir characterization, it was essential to integrate all reservoir-related data from macro to micro scale. X-ray Fluorescence elemental data collected from offset cores were used to predict key rock attributes and calibrated with standard petrophysical logs. The scope was constructing predictive models for the following properties:lithological variations which cannot be captured by other LWD toolsdetailed mineralogy to determine the diagenetic overprintdepositional environment of different Burgan sand facies.
XRF elemental analysis while drilling was used to improve borehole positioning, and identify faults in correlation with Image logs. Nature of the fractures/faults, contributing to porosity and communicating with the aquifer, was inferred from XRF-obtained elemental markers. The integrated approach has resulted in successful geosteering and placing the well with maximum reservoir contact. Moreover, XRF elemental markers have been utilized for isolation of faulted and lower reservoir quality zones, splitting up of horizontal sections and optimization nozzle sizes of the ICDs and hence an optimized Smart completion design. X-ray fluorescence analysis on cuttings in Real-Time provides lithological information otherwise not available while drilling. It gives proxies contributing to the identification of faults and reservoir intervals in an otherwise homogeneous sequence. It helps designing the completion string, isolating sections of low quality or potentially producing water.
Optimizing Dehydrators Operation Using Dynamic Adsorption Time
Authors: Almakrami Eisa A , Gadi Amr A. 
Published: May 2016

Abstract
Molecular sieve is a solid desiccant widely used in gas plants for dehydrating wet process gases. Compared to other desiccants, molecular sieve can reduce water content in the outlet gas to less than 0.1 ppmv. This is a must requirement for conditioning feed gas to cryogenic applications. On the other hand, Molecular Sieve is generally more expensive and energy exhaustive.
This paper describes the successful implementation of the Dynamic Adsorption Time Control Module for dehydrators in natural gas liquid (NGL) recovery trains at Saudi Aramco's Hawiyah NGL Recovery Plant (HNGLP). The module optimally utilizes the available dehydrators capacity by applying dynamic adsorption time for dehydrators based on available desiccant capacity, processed gas flow and incoming water content. As a result of this optimized utilization, the frequency of regeneration cycles is reduced. This results in extended desiccant lifetime, and reduced lost revenue and energy consumption over the desiccant life cycle.
Useful Recycling and Safe Disposal Technology of Waste Oil Based Drilling Fluids and Its Application
Authors: Xie Shuixiang , Deng Hao , Wang Rongsha , Yue Yong , Wu Baichun , Liu Guanquan , Xu Yu 
Published: May 2016

Abstract
Waste oil-based drilling fluids are hazardous wastes containing oil, heavy-metal and organic pollutants. However, the common treatment methods at home and abroad these methods not only waste many useful resources (because the oil is discarded rather than recovered) but also increase the pro-environment cost of oil companies. This paper develops useful recycling and safe disposal technology of waste oil-based drilling fluids from the perspective of utility, efficiency and economy, which not only recycle useful oil but also reuse and dispose of the rest of mud and waste drilling fluids. The rate of recovery is greater than 90%, and the quality of the recycled oil is very good and meets the requirement of -10 # diesel of cars in GB/T 19147-2003. The concentrations of oil, COD (chemical oxygen demand) and heavy metals in liquid of the processed mud are lower than the secondary standard number in GB8978-1996. The treated wastewater meets the requirements of sewage comprehensive emission.
Equation for Oil and Gas Two-Phase Flow into Vertical Well - A Theoretical Derivation
Authors: Ling Kegang , He Jun 
Published: May 2016

Abstract
Generally reservoirs are classified into five categories according to the reservoir fluids. Single phase flow in reservoir is expected during the production life for wet gas and dry gas reservoirs. But for black oil, volatile oil, and gas condensate reservoirs, two-phase flow will occur after pressure declines to saturated pressure and the second phase saturation reaches the critical saturation. Theoretical derivation of single-phase flow into vertical well had been done by former investigators. The solutions to different boundaries at different flow status were provided through different simplifications and assumptions. These solutions provide powerful tools for reservoir study. But when it comes to oil and gas two-phase flow, they cannot be applied. To the best of our knowledge there is no rigorous and theoretical derivation for the oil and gas two-phase flow into the well.
In this study, rigorous and theoretical derivation of oil and gas two-phase flows from reservoir into the well was conducted. Starting from the famousDarcy's equation, the flows of oil and gas are controlled by the rock/fluid properties, pressure, and temperature condition. The continuity equation was applied. With the combination of equations of state and the concept of compressibility, the governing equation of oil and gas two-phase flow was constructed. Even numerical approach is required to solve the equation to get gas and oil flow rates, the new equation still has its significance due to its theoretical and rigorous derivation. It can be used as a unique tool to solve the saturated oil and gas condensate reservoirs that experience two-phase flows. The proposed equation addresses the rigorous derivation of two-phase flow in a radial reservoir. It eliminates the uncertainty in the empirical equation and has the advantage of quickness and simplicity comparing with reservoir simulation method. It becomes a powerful tool for petroleum engineers.
Upstream Stranded Raw Gas Management as Compressed Natural Gas (CNG)
Authors: Economides Michael J. , Wang Xiuli , Colafemmina Francesco , Tomaselli Vanni Neri 
Published: May 2016

Abstract
Marine compressed natural gas (CNG) has been considered in the past as a means of natural gas transportation but proved to be a non-starter for a number of reasons including long distances or large volumes of gas when compared with liquefied natural gas (LNG). However, marine CNG still figures economically attractive over shorter voyages (up to ~4,000km) and medium volumes of gas. Recent advances in containment systems are poised to provide marine CNG with the best opportunity to be resurrected as a major enabler of new and previously stranded hydrocarbons by becoming an important optimization tool to petroleum well performance.
Almost half of offshore natural gas, SEC-type, reserves are considered" stranded" because of the high unit technical cost to harness natural gas in remote locations involving deep-water and/or pre-salt basins, and the lack of are liable and commercially viable market for the natural gas. Most of them do not contain enough gas to justify their own gas transmission solution, floating or onshore LNG production. Furthermore, inoperable gas affects oil production in many adverse ways from the logistics of handling and facilities capacity to the cost of the treatment. Marine CNG used as a wellhead fluid shuttling service for raw gas can generate significant monetary benefits for an operator attributable directly to the new technology and innovative application. Gas viewed like this is no longer a mid-stream product in need of further processing prior to sale, but becomes a potential upstream saleable product.
We present here the new technology emphasizing the containment system manufactured with composite materials that are far lighter than metal and yet can withstand the 200-atmosphere pressure and corrosion from hostile raw gas composition straight out of the primary separator. CNG cargo containment system produced with composite materials can reduce overall steel weight by 50–80% and can operate with pressures ranging from 150 to 250 bars, sufficient to accommodate a wide range of gas-oil-ratios without the need of refrigeration.
Paleogeomorphology Analysis and its Application in Exploration and Production of Karstic Ordovician Carbonate
Authors: Yang Haijun , Tong Yanming , Deng Wensi , Yang Pin , Pan Wenqing , Chen Lixin , Lei Xue , Wu Chuan 
Published: May 2016

Introduction
The Ordovician carbonate karst reservoir which is usually buried 5000m deep is an increasingly important target for oil exploration and production in Tarim Basin, West China. The paleogeomorphology of the top of the Ordoviciancarbonate directly controls reservoir development and hydrocarbon accumulation, so detailed characterization of karst paleogeomorphology is one of the keysteps to identify reservoir development rules which will lead to more efficient exploration and production activities in the study area.
This paper presents an example study on carbonate karst paleogeomorphology in Tarim Basin. Also, its significance to exploration and production activities has been discussed.
Integrating True Valve Performance into Production System Analysis Based Gas Lift Design and Troubleshooting for Dukhan Field, Qatar
Authors: Singh Sanjay K. , Hall James W. , Khalil Eraky , Al-Marri Balsam , Al-Abdulla Reem 
Published: May 2016

Abstract
Qatar Petroleum's Dukhan field uses gas lift to produce oil wells that cannot sustain natural flow because of reservoir pressure decline or rising water-cut. The increasing number of wells on gas lift has made the effectiveness of gas lift design and troubleshooting a key factor to achieving crude oil production targets. Until the present day production system analysis methods were used for gas lift design and troubleshooting. This was found to be inadequate in several cases to achieve an optimum design or to troubleshoot problems successfully. To resolve such inadequacy, a new approach has recently been applied that makes use of the VPCTM (Valve Performance Clearinghouse) database. The VPCTM database provides tested or true performance data for gas lift valves. The new approach integrates well performance from production system analysis and true valve performance from the VPCTM database into an integrated system performance tool. Sensitivity analysis of the integrated system is then performed with a set of well conditions and valve parameters for gas lift design or troubleshooting. The paper focuses on the intricacies of the approach and presents a typical field example of its application. Application of this approach has enabled effective gas lift design and troubleshooting, unlocked incremental oil potential at negligible cost and extended the producing life of wells.
Simulation of Chemical Interaction of Injected CO2 and Carbonic Acid Based on Laboratory Tests in 3D Coupled Geomechanical Modelling
Authors: Masoudi Rahim , Abd Jalil Mohd Azran , Tan Chee Phuat , Press David , Keller John , Anis Leo , Darman Nasir , Othman Mohamad 
Published: May 2016

Abstract
The M4 field is located in the North of the Central Luconia Province in the Sarawak Basin, East Malaysia. The reservoir is approximately 2000 m below sea-level where the water depth is approximately 120m. A study for CO2 geological storage has been carried out to address the feasibility of injecting and storing CO2 in the M4 depleted carbonate gas reservoir using 3D coupled geomechanical modeling. The water level in the reservoir has risen close to the cap-rock which implies a strong aquifer.
Laboratory tests were carried out on core samples before and after injection of a CO2 saturated brine solution, and the results were used in the determination of material property strength and elastic property degradation due to acid-carbonate interaction. Triaxial compression tests on carbonate samples from three different depths at the peak loading stage of the tests for different confining pressures were performed. The effects of CO2 saturation on UCS, Young's modulus and Poisson's ratio were determined. The permeability measurements from the pore volume compressibility tests and permeability measurements obtained during the measurements of petrophysical properties were used to evaluate the effects of acid-carbonate interactions.
The 3D geomechanical model coupled the reservoir pressures derived from a dynamic model with a stress simulator in order to calculate changes in effective stress and volumetric strain within the 3D model. The derived changes in volumetric strain were related to a change in porosity and permeability which were then passed back to the dynamic model in a staggered solution scheme. At each "stress step" in the solution process, a further modification was made to geomechanical material properties due to the increased CO2 saturation from injection. The material parameter modifications were based on the results of the laboratory tests above. In this way, the material property degradation due to CO2 injection was accounted for during the coupled reservoir geomechanical simulations.
The paper discusses the results of these tests and the derived variation of material permeability, elasticity and strength parameters with CO2 saturation for subsequent input to the coupled geomechanical solution scheme. In this way, the potential risk due to the chemical interaction from CO2 injection could be evaluated quantitatively.
Casing Failure Mechanism and Characterization under HPHT Conditions in South Texas
Authors: Yuan Zhaoguang , Schubert Jerome , Esteban Urdaneta Carbonell , Chantose Prasongsit , Teodoriu Catalin 
Published: May 2016

Abstract
Casing failure probability is high in Ann Mag Field, South Texas due to the high pressure high temperature operational environment. The formation sands are over-pressured where the pore pressure ranges from 0.85 to 0.93 psi/ft. Casing damage has been experienced in over 11 wells from 18 that have been drilled in the area, near 61% of total wells were damaged during their production life.
Casing failure may be caused by formation shear failure, formation compressive failure, casing tension failure, casing collapse or fault activation. Casing buckling is not considered in the study because cement bond logging shows that the cement sheath is good. Triaxial tests were carried out to measure formation mechanical properties that were used for reservoir compaction, fault activation and formation failure analysis. The Mohr-Coulomb failure criterion was applied to study the formation failure and the minimum pore pressure required to activate the fault. The finite element methods were used to analyze the casing tension failure caused by reservoir compaction.
According to the formation shear failure analysis, the minimum allowable pore pressure around the casing is around 2,000 psi. In the study of fault activation, for shale formation, at the internal friction coefficient of 0.51, the probability that the normal fault can be activated is very high. The maximum drawdown and depletion were calculated based on potential casing failure types. In the plot of workability operational limits, shale formation has narrower safe zone than the sand formation. Recommendations for drilling and production were made to increase the well service life and improve the gas recovery.
This paper presents the casing failure mechanism and characterization under HPHT conditions in south Texas that can be prevented in the future wells and provides workability operational limits for different formations.