bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Method of Quickly Evaluating the Fracture Complexity of Network Fracturing
Authors: Yuan Xeufang , Zhang Yang , Liu Ju , Peng Fen , Teng Qi , Xiao Yang , Yi Xiangyi , Han Xu 
Published: November 2016

AbstractGas reservoir K in Tarim oil field which is an abnormal pressure fractured tight sand reservoir may generate complex fracture due to the high rock brittleness. Microseismic monitoring technology is a effective methods of evaluating the network fracturing, but it had been limited by economic cost and service conditions. With the extensive application of SRV, it is necessary to develop a fast and economic way to evaluate the complexity of network fracture in hydrofracture. The reservoir types and the fracture morphology were evaluated by analysis on the pressure drawdown after pumping, and the fracture complexity evaluation was completed by G function feature identification. Based on the above two points, a fast method of evaluating the complexity of network fracture had been created. The results of microseismic monitoring in several wells had verified the feasibility to this method which will provide basis and support for production prediction.The date matching results shows that this method in our study strongly consistent with the collected field information. So, we can draw some conclusions as follows: (1) the analysis of pressure drawdown based on injection/drawdown theory could effectively identify the main flow types after stimulation. (2) the complexity of fracturing cracks and the natural fractures could be identified with G function analysis. (3) the results concluded by analysis of pressure drawdown and G function is consistent with the conclusion with Microseismic monitoring technology. The advantage of this research is that a rapid and practical evaluation method based on the fracture complexity evaluated by pressure drawdown analysis and G function analysis for hydraulic fracturing is formed.
Polymer EOR - A New HSE Hazard in an Old Industry
Authors: Bridgewater S. , Goldszal A. , Milani A. 
Published: November 2016

Abstract
There is an increasing trend in the oil and gas industry for the use of Enhanced Oil Recovery (EOR) techniques to improve the oil recovery from the reservoirs. The industry is well established to manage the hazards associated with hydrocarbon liquids and gases. However, polymer powder, used for Chemical EOR, presents a new set of hazards that needs to be incorporated into the HSE design of these facilities. This paper presents the main HSE design aspects to be addressed for the management of the process safety, environmental and personnel safety hazards introduced by polymer EOR facilities in the oil and gas industry.
Total has conducted a number of Chemical EOR studies and implemented pilot plants, with an aim to developing full oil fields based on polymer flooding of the reservoirs. A comprehensive review of these polymer projects has been carried out and the HSE lessons learnt have been assessed. Information from polymer suppliers has also been reviewed, supported by an extensive literature review of the HSE requirements and standards for other powder handling industries. The review focused on the HSE design aspects for those polymer EOR projects that use powder as the source material.
Hazards related to the handling of powder based products are effectively managed in other industries and documentation exists to guide designers on the requirements for managing these hazards in their processes. The use of polymer powder is not new to the oil and gas industry, however, very little guidance exists, to account for this hazard as part of the HSE design of the oil and gas facility, as it is less understood compared to the hazards presented by flammable oil and gases. An HSE guideline has been prepared to enable a better understanding of the hazards of using polymer powder in EOR facilities. The guideline serves as a bridge to facilitate the incorporation of this new hazard into an already established safety design management process. This paper presents the main HSE design aspects from this guidance document and addresses key areas such as flammability and dust explosion; area classification and ignition control; drainage and spill containment. The personnel safety requirements to protect the plant operators are also addressed.
A Probabilistic Model to Evaluate the Operation Reliability of the Underground System in Underground Gas Storage Transformed from Depleted Gas Reservoir
Authors: Song X. , Peng C. , Li G. , Wen K. 
Published: November 2016

Abstract
Underground gas storages (UGS) have been built around the world. Several UGS are transformed from depleted gas reservoirs near Beijing. UGS wells always endure complex working load, having high possibility of failure. Besides, repetitive injection/production circles induce dramatic periodic changes of pore pressure and wellbore stresses, meaning formation breakdown can be triggered. On account of these facts, it remains necessary to verify whether we can produce or inject gas as planned in UGS.
A probabilistic model based on stress-strength interference theory is set up to evaluate the reliability of the underground system, i.e. wellbore (tubing, casing and cement sheath) and formation. Firstly the strength and stress functions are established with material parameters and in situ stresses for these four parts. The parameters and forces are random variables in nature so all the strength and stress are random variables as well. Special attention is paid to the effect of erosion. Then the operation reliability of each part is the probability that strength is larger than stress, obtained using Monte-Carlo method.
The total operation reliability of underground system is defined as the weighted average of the reliabilities of the four parts. With productivity formula and wellbore flow equations embed, this probabilistic model is able to give the reliability (probability) of the underground system accomplishing the task of injecting/producing scheduled amount of gas into/from the formation within scheduled days. Note that the everyday change of pore pressure is considered in order to monitor the change of operation reliability with time. Several validation cases including injection and production are given and this model is able to give the operation reliability. It can help to clarify the potential problems such as casing collapse and sand production so that advance workover or adjustment can be performed. It is concluded that the probabilistic model raised in this paper is not only reasonable in theory but also cogent in practice.
This is the first time that stress-strength interference theory is employed to evaluate the reliability of the underground system in UGS. It is proven this model is valid and tress-strength interference theory has the potential to be applied in other reliability estimations of petroleum equipment and structures.
Unlocking Future Petroleum Potentials with Exploration Discoveries in North Malay Basin, Malaysia-Thailand Joint Development Area
Authors: Adnan M. Mohd , Ismail W. Wan , Kaewtapan J. , Setiawan A. S , Tanprasat S. 
Published: November 2016

Abstract
A comprehensive technical evaluation was conducted after the completion of six exploration and appraisal wells to assess the future petroleum potentials in North Malay Basin, offshore Malaysia-Thailand Joint Development Area (MTJDA). This paper focuses on major discoveries and findings from key wells, namely Well-E3, Well-A2ST, and Well-T3 to better understand the petroleum potentials for the subsequent development planning.
Well-E3 and Well-A2ST were drilled to investigate the stratigraphic trap play in the eastern flank of MTJDA and to explore the hydrocarbon potential in deeper depositional sequence below DS10 interval. The seismic dataset and amplitude analyses were used to identify channel fairways and qualitatively predict sand presence for well planning optimization. Both wells encountered gas-bearing sands with proven stratigraphic trap style, requires channel orientation oblique with the axial anticline structure. Full integration of well log dataset, formation pressure test and seismic attribute analyses have proven the exploration intervals with gas-bearing sands discoveries. In addition, rock physics analysis was performed to differentiate gas from wet sand and coals.
Well-T3 was drilled in the western flank to appraise the seismic anomaly associated with hydrocarbon sand and to investigate the CO2 content in the southernmost extension of hydrocarbon accumulation. The anomaly is observed as two distinct sand fairways of channel-bar complex. The northern lobe was dissected by deep seated fault system with high CO2 content. The southern lobe appears to be free from deep seated fault system. Well-T3 was drilled in the area where CO2 pathways was expected to have no connection with deep seated fault system and lower CO2 content than the main area. Formation pressures, samples and seismic anomaly supported the hypothesis that the northern and southern culminations are not connected with significant stratigraphic heterogeneity interpreted. An important oil discovery was also observed from pressure gradient and samples as the first oil discovery in the western flank.
Full integration of the well log dataset, formation pressures, seismic attribute analyses and rock physics modeling have resulted in an improved understanding of reservoir distribution and reduced the degree of uncertainty in reservoir connectivity, thus allowing a more robust development strategy. The new discoveries of proven stratigraphic trap in the eastern flank with deeper hydrocarbon culminations and proven oil discovery in the western flank with enhanced understanding of CO2 content have triggered more future petroleum potentials in MTJDA acreage.
Applying the Learning from The Gulf of Mexico Response to Enhance Emergency and Oil Spill Preparedness
Authors: Flynn Steven A 
Published: November 2016

Extended Abstract
The Macondo blow-out in the Gulf of Mexico in 2010, and the earlier Montara incident in Australia, led the entire oil and gas industry to review both drilling safety and oil spill preparedness. As a result, the International Oil and Gas Producers Association (IOGP) established a multi-year programme to embed the learning from these and similar incidents, and to enhance future prevention and preparedness. This presentation provides an overview of the latest practical tools that can be used by operators to improve their emergency and spill response plans.
Wavelet Extraction and Local Seismic Phase Correction Using Combination of Different Moment
Authors: Naghadeh Diako Hariri , Morley Christopher Keith 
Published: November 2016

AbstractIn this paper wavelet phase is extracted using a combination of different moments (CDM), which is introduced as an indicator of localized seismic signal phase. The analysis demonstrates sharpness of the probability distribution of a discrete time series that is more robust than applying kurtosis. The improvement occurs because zero-phase wavelets with reverse polarities have equal maximum kurtosis value hence the correct wavelet polarity cannot be identified. Zero-phase wavelets with reverse polarities have minimum and maximum CDM values. Those enable the technique to handle a finite data segment based on the combination of different moments and it can also choose the correct wavelet polarity. High order statistics are sensitive to outliers so they will be instable in region with high level of noise. Combination of different moments can solve or decrease this limitation because of existing of low degree behind high degree moments. The most important parameter for correctly estimating the phase pertains to the best length of time window used for phase correction. Incorrect window length creates non-zero phase wavelets. To decompose signal to wavelets, an envelope of each trace is applied. Based on the time distance between two minima of envelope value, it is possible to choose the wavelet lengths to do phase correction. Synthetic and real data examples are used to demonstrate the effectiveness of this method in both wavelet extraction and for local correction of signal phase. Results of the seismic phase correction using this method demonstrate superiority than the local kurtosis method, because of high stability and dynamical range.
Rock Physics Applications for Seismic Interpretation in the Gulf of Thailand
Authors: Wilkins Michael , Pambayuning Sherry 
Published: November 2016

Abstract
Before undertaking any seismic interpretation project, it is essential to understand the rock physics of the area so that the interpreter knows what to look for in their seismic. Rock physics modelling can be used to predict the effects of lithology, fluid, porosity, depth and sand thickness on the seismic response. It can also help to understand whether direct hydrocarbon indicators (DHIs) such as flat spots, bright spots, dim spots or polarity reversals are expected and also the best seismic attributes to use to identify hydrocarbons. Well ties can be used to determine the quality of the seismic data and infer how reliably predictions based on the rock physics can be applied back to the seismic data.
The rock physics of several producing assets across the Gulf of Thailand have been examined and compared. Rock properties of over 200 wells have been analyzed based on stratigraphy, lithology, fluid fill, facies, porosity and depth. It was observed that the rock physics could be split into two distinct regimes based upon depositional environment separated by a key unconformity.
The first rock physics regime is observed in the shallow high porosity fluvial systems found within the Nong Yao Field and the younger reservoirs of the Jasmine and Manora Fields. In this regime, seismic attributes and seismic inversion have been successfully used to predict sand presence and thickness. Sands and shales have distinctly different rock properties and sands produce a strong class III-IV Amplitude Varation with Offset (AVO) response. Fluid effects can be observed on seismic although it is difficult as thickness and porosity changes may be incorrectly interpreted as fluid changes. The second rock physics regime is observed in the older, lower porosity lacustrine system found within the main reservoirs of the Manora Field and the pre-MMU reservoirs of the Jasmine Field. Within this regime, lithology prediction is much more difficult as sands and shales have very similar properties. Sands are modelled to have a class I-II AVO response and fluid effects are minimal.
Understanding the rock physics of these fields allows future work to be focused appropriately. At the Nong Yao Field and in the younger section of the Jasmine Field, technical work is focused on seismic inversion, seismic attribute analysis and other geophysical techniques for lithology and fluid prediction. Whereas at the Manora Field and in the older reservoirs of the Jasmine Field, technical work is focused more on structural mapping and geological modelling, and amplitude analysis is of lower priority.
Innovative Booster Compressor for Marginal Wellhead Platform
Authors: Sillapacharn Thitinun , Srichompoo Sireekorn , Hoonsuwan Phakhachon , Aroonsangob Peeradet , Jirarungsakunruang Sumate , Nitipan Tunchanok , Vasansiri Kritithy 
Published: November 2016

Abstract
It is recognized that several problems, including equipment redundancies and valuable space consumption, exist in the wellhead platform. For example, there are separators installed to separate gas and liquid that come from reservoirs at various operating pressure conditions. The challenge is to integrate these separators in to a single separation unit for space reduction as well as to broaden operating conditions to serve multiple process conditions.
A three-phase test separator together with drain vessels are installed at the wellhead platform in order to execute reservoir management, well monitoring program, and well intervention activities – such as well clean-up during start-up and liquid unloading where gas flow rates are too low for export due to liquid obstructions in well tubing. Furthermore, booster compressor and associate separation system are installed when the wells deplete to the point where they cannot be produced at under natural production conditions. The operation of the booster compressor allows lowering of the wellhead flow pressure and increasing in the reserve recovery factors.
To address the concerns of the oil price crisis and smaller gas prospects in the field, an Innovative Booster Compressor Package has been developed to serve two aspects of value improvement, (i) to minimize an investment cost and (ii) to maximize and ultimate recovery reserve.
To minimize an investment cost, the booster compressor inlet separator and separator blowcase were re-engineered and modified in order to maintain functions of test separator. The gas and liquid flowmeters can work together with an additional watercut meter enabling the determination of fluids flowrate. During the well unloading operation, well fluids entering the inlet separator at very low pressures and will be transported to the export pipeline with assisted gas from the booster compressor discharge line. This modification results in the elimination of the three-phase test separator and the drain system.
To maximize an ultimate recovery reserve, a compressor will either be operated at a high pressure suction with two parallel cylinders, or at a low pressure suction with two cylinders in series configuration. This allows lowering of the abandonment pressure and increasing the recovery factors of these wells. As a result, this swicthable configuration concept can incrase gas protential and assist in sustaining gas production.
A successful development of the Innovative Bosster Compressor has two benefits. First, at least twenty percent (20%) less investment cost is achieved because of the direct cost savings from vessel integration and from topside-area optimization. Second, an estimated ultimate recovery gain from a switchable low pressure booster compressor is expected at about three percent (3%) higher. These are significant efficiency improvements in the economics of the E&P industry.
Engineering a Fit-for-Purpose Bit Doubles Performance and Durability in Abrasive and Impact-Prone Formations
Authors: Agawani Waleed , Al-Saffar Waleed M. , Omar Marwa , Al-Shehab Ahmad Y. , Taha Mohamed , Ahmed Tausif , Abdelhamid Atef , Al-Awadhi Shaimaa 
Published: November 2016

Abstract
The Umm Gudair 12.25-in. vertical drilling performance section involves several technical challenges for engineering an application-specific PDC bit. The interval consists of two formations that require contradictory bit design principles. The abrasive Zubair formation incorporates sandstones interbedded with hard shale streaks, followed by dual Ratawi intervals of hard shales that are succeeded by compacted limestone. The initial sand interval abrades the cutting structure, resulting in slower rates of penetration in the deeper carbonates. The premature dulling of cutters then causes lower carbonate drilling efficiency. Typically, the section is drilled at 35 feet per hour (fph) and requires 2 bits to complete.
After reviewing offsets with faster than average rates of penetration that successfully completed the interval in the same application, a design compromise was achieved. The new optimized bit design is based on a seven-bladed bit with sixteen-mm cutters. Subsequent design iterations optimized the cutter selection and the cutting structure to maximize durability in the sands while remaining aggressive enough to drill the lower carbonates. An iterative design-and-simulate process then followed, simulating bit stability against formation strength data and optimising drilling fluid flow dynamics. The design was adjusted repeatedly based on the simulation results until a balance in aggressiveness, stability and flow was reached.
After the design process concluded, optimal drilling parameters for each formation were drawn up from offset wells, and the new design was field tested. Drilling stability improved in the sand interval while cutting structure integrity was sustained into the deeper carbonates, resulting in improved rates of penetration in both intervals. After several runs, the results demonstrated that significant gains in rates of penetration were made; reaching over 90 feet per hour (fph) in some cases, almost doubling current rates of penetration. The post-run dull condition of the bits tended to be virtually new (1-1-WT), and in one instance the bit re-ran on a second well, drilling the interval at 53fph.
This paper demonstrates a successful engineering design process for such a challenging section in the Umm Gudair Field. It then highlights the technologies featured in this bit and their value in drilling this application. Finally, field test results are analysed and the improvements in drilling performance and time and monetary savings to the operator are quantified.
Full Waveform Inversion of Cross-Dipole Acoustic Waveforms
Authors: Fuse S. , Mikada H. , Takekawa J. 
Published: November 2016

Abstract
In the present study, we examine the possibility to estimate the anisotropic properties of formations from the waveforms obtained by acoustic logging using numerical simulation. Our numerical model includes a vertical borehole in anisotropic layer with various azimuths. The anisotropic layer is set as transversely isotropic medium with a horizontal axis of symmetry (HTI) or transversely isotropic medium with a tilted axis of symmetry (TTI) which has 5 independent elastic parameters in the stiffness matrix. It has been assumed in the acoustic logging that the medium to estimate the anisotropy is HTI or TTI with a subtle tilt angle under the assumption of weak anisotropy and the shear wave splitting is used to estimate the azimuthal angle and the order of anisotropy with cross dipole acoustic measurements. Since it is necessary to have a general method that could deal with TTI in terms of both the tilted angle and the order of anisotropy, we conduct numerical experiments under a hypothesis that the cross dipole waveforms could be exploited for further data processing. We then apply a method of Full Waveform Inversion (FWI) for acoustic logging model in isotropic medium to investigate the effectiveness of the method. Our results show that the waveforms include information about the anisotropic layer even if no difference can be observed in the travel time. Besides, it is suggested that FWI technique for anisotropic medium should be useful to estimate the anisotropic parameters in the acoustic logging.