bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Probabilistic Neural Network on Complex Carbonate Reservoir Prediction
Authors: Sun Xuekai , Sun Sam Zandong , Jiang Shan , Luo Chunshu , Yang Haijun , Pan Wenqing 
Published: May 2016

Abstract
Carbonate reservoir in Tarim basin is more complex for its strong heterogeneity and anisotropy. Different from the usual, this paper mainly focused on how to employ PNN as a comprehensive method in detecting the dissolved caves for carbonate reservoir, in which advantages of inversion and attributes are both used. During the entire workflow of PNN, we emphasize the importance of seismic attributes searching and cross validation. And the P-velocity and S-velocity of a test area selected from ZG8 area are predicted by utilizing PNN technique, and the interpretation of Formation Yingshan is conducted on the established indicator of Vp/Vs. Results show that the resolution is greatly boosted and the dissolved caves are distinctively and vividly characterized, which is seldom achieved by pre-stack inversion.

1 Introduction
The great potential of carbonate reservoirs in Tarim basin is widely accepted. However, situations are rather complex than conventional reservoirs. In the past geological history, carbonate rocks in this area experienced multi-staged tectonic movements and dissolutions. Consequently, the main storage space for oil and gas at present are mainly the dissolved caves and fractures instead of the primary pores. Strong heterogeneity and anisotropy brings great difficulties and challenges for discovering and characterizing complex carbonate reservoirs (Sun et al., 2012). For this reason, it is obvious that only a single technique is insufficient to deal with the challenges we meet in complex carbonate reservoir prediction.
And the theoretical basis of probabilistic neural network (PNN) is founded and improved by Specht and Donald in early 1990s. Actually, PNN is more like a mathematical interpolation scheme which happens to use the neural network architecture for its implementation. Compared with multi-layer forward network, PNN behaves much better for its remarkable robustness and efficiency. PNN was first used in the image and signal processing (Masters, 1995), and it was Hampson that introduced this technique into geophysical world through a case study, in which the the porosity of a sand reservoir was successfully estimated by incorporating several attributes (Hampson et al., 2001).Although many studies and practices proved that PNN can serve as a powerful tool by incorporating various results from different explanation techniques in the past decade(Xie et al., 2004; Wang et al., 2004; Wu et al., 2011), however, carbonate reservoir is seldom involved in these studies.
Potential Application of Downhole Gas Compressor to Improve Productivity for Gas Reservoir
Authors: Hossain Md Mofazzal , bin Mohd Ismail Mohd Dali 
Published: May 2016

Abstract
Downhole Gas Compression (DGC) is the new form of Artificial Lift Technology used to increase the productivity of gas wells. Surface compressors are commonly used to reduce the pressure at the wellhead, which in turn reduces flowing bottom hole pressure, and boost the well productivity for a gas well especially during its decline phase when average reservoir pressure falls to a value equal to the pressure in the wellbore imposed by the sales line at the surface, plus the pressure losses that occur in the gathering system and the tubing. This conventional technique is not very efficient for the gas wells that produce significant amount of liquid (water or condensate), since this liquid needs to be separated before reaching the gas compressor. In addition, it also requires additional space for compressor assembly into the well, which may be very challenging for wells in offshore and subsea environment. As an alternative to surface compressors, down hole gas compressors technique can be applied to increase the well productivity, especially gas wells in offshore and subsea environment. Some study claimed that this new technology could: increase more than 30% of gas production; resolve many multiphase related issues; and delay the onset of liquid loading. However, numerous challenges associated with design, development and implementation of this new technology are not well understood or documented. This study has been focused to understand the key concepts of the technology and explore its potential application for increasing well productivity of gas wells through sensitivity studies. This paper presents principles mechanisms including theoretical background of DGC techniques, and results of sample case studies based on sensitivity analysis with aims to identify key factors to be considered for successful deployments of DGC into a gas well for natural gas reservoir. The paper also summarizes key findings which may be used as potential guidelines while considering for possible implementation of DGC technique during field development planning.
Determination of Effective Flow Properties of Caprocks in Presence of Multi-Scale Heterogeneous Flow Elements
Authors: Ma Jingsheng , Couples Gary , Drews Michael , Kurtev Kuncho , Aplin Andy 
Published: May 2016

Abstract
Determining the effective fluid retention capacity of caprocks is of importance to petroleum exploration and production, and to CO2 storage in the subsurface. Thick successions of mud-rich sediments can comprise a range of genetic units (GUs), including mud-dominated hemipelagites, channel-levees, and mass-transport deposits. These GUs are characteristic of slope settings within the deep-sea environment. Based on measured properties of small samples, mud-rich sediments within these GUs ought to be high-quality caprocks with very low permeability and high capillary entry pressure (Yang & Aplin, 2007). However, each GU also contains objects of much more permeable materials such as fine sands and silty sediments. Those bodies are in the form of sub-seismic, typically centimeter thick, thin layers, which may or may not be deformed during the process of basin evolution, but they can have considerable lateral continuity. Moreover, GUs may contain deformation-related flow conduits, such as sandy injectites and open fractures, which function as pathways for vertical fluid migration. These GUs may themselves be arranged in complex patterns due to depositional and deformational processes. Such multi-scale heterogeneity in caprocks can affect their fluid retention capacity.
Estimating the effective fluid retention capacity of caprocks involves the quantification of properties at a sample (10-2m) scale in the laboratory. Sample compressibility, permeability and threshold Capillary Entry Pressure (CEPt) could be constrained well by lithology (e.g. sand/silt/clay ratio) of sediments, and at normal conditions they could encapsulate finer-scale heterogeneity satisfactorily too. However, the direct use of those properties on blocks of 1000mx1000mx100m size in basin simulations is highly undesirable and risky if each block corresponds to full or part of one or more heterogeneous GUs. Therefore, the lab-based properties must be upscaled to the block scales through multi-stage upscaling. To do this, we need: "to recognize the geometric arrangements at appropriate length scales; to construct models that capture these arrangements; to populate them with appropriate small-scale properties; and to run flow simulations from which it is possible to determine the effective properties at the target scales" (Aplin et al., 2012). This approach also provides knowledge about the types of sedimentary and mechanical architecture that forms the critical controls, and the conditions under which these features affect fluid flow at chosen length scales. We have developed a set of techniques to recognize structural arrangements from core, well-log, outcrop, and seismic data, to construct constrained models from these observations, and to calculate effective properties by flow simulation.
Thermo-Dissoluble Polymer for In-Depth Mobility Control
Authors: Bai Baojun , Zhou Jia , Liu Yuzhang , Tongwa Paul 
Published: May 2016

Abstract
Gel treatments have been implemented as a cost-effective method for plugging high-permeability zones and thus improving sweep efficiency in reservoirs. However, when extensive cross-flows exist between formation layers, near wellbore gel treatments become less efficient. Polymer was used in polymer flooding to increase the viscosity of the injected fluids in order to improve the oil recovery. However, the efficiency of polymer flooding is limited by the dramatic viscosity loss (80–90%) caused by various shearing degradations during the polymer injection process and polymer transport at extremely high flow rates in near wellbore formations. This research focused on developing a novel polymer, which first is injected into fractures or fracture-like features as a millimeter-sized particle gel (50 um to a few millimeters) and acts as a plugging agent, and then dissolves into polymer solution at a designated time (e.g., 6 months) due to the reservoir's temperature; the dissolved polymer seeps into the depths of the formation to behave as a mobility control agent. The polymer dissolution process occurs under reservoir conditions, so the polymer's viscosity will not be influenced significantly by the degradations from pump, wellbore and near wellbore porous media. This paper will report the evaluation results of the new product. Several evaluation methods have been established to characterize the properties of the new polymer system before and after their dissolution. It has been found that the time it takes for the solution to dissolve depends primarily upon the reservoir temperature and liable crosslinker concentration. ESEM pictures revealed that the 3D polymer network of novel particle gel transformed into linear polymer after the polymer gel totally dissolved. Coreflooding experiments showed that the dissolved polymer exhibited excellent water resistance.
Successful Application of a New Electromagnetic Corrosion Tool for Well Integrity Evaluation in Old Wells Completed with Reduced Diameter Tubular
Authors: Zhang Shujing 'Peter' , Guergueb Nacer , Garcia Javier , Yateem Karam Sami , Sethi Neeraj 
Published: May 2016

Abstract
As the number of aging wells grows in the oil and gas industry, there is a recurrent need for monitoring the health of these wells over their productive life and providing assurance of the integrity of the well barriers that isolate them from uncontrolled formation pressure and fluids. Tubing and casing condition evaluation is a crucial aspect of this evaluation. The industry utilizes a number of conventional technologies for evaluation of tubing and casing integrity, such as internal mechanical calipers, electromagnetic and ultrasonic thickness (UT) tools, which are generally quite satisfactory for the evaluation of the inner casing but are often affected by internal tubular diameters in terms of their application. Most conventional tubular evaluation tools are unable to evaluate multiple concentric barriers. When combined with the low diameter production tubing completions the options for evaluating the production and outer casings become very limited, necessitating the need to pull the inner casing by performing a workover at a considerable expense and inspect the outer casing with conventional technology. A new electromagnetic casing corrosion evaluation technology was applied in a group of critical wells completed with small diameter tubing. The technology utilizes electromagnetic pulsed transient eddy currents to simultaneously inspect tubing and the casing behind it and provide quantifiably segregated measurements of thickness in the tubing and the first concentric casing as well as qualitatively characterized by a third casing string. This slim tool with a diameter of 1-11/16" allows measurements through slim production tubing. The objective of the study was to assess the integrity of a group of mature wells completed with small diameter restrictions, near populated areas and associated with high H2S environment. This study includes the candidate generation, field application, results evaluation and general recommendations for the well integrity program. The results exhibited that the data obtained from the tool is reliable. A quantifiable assessment of the metal loss of casing behind the tubing could be made, which made a mitigation strategy possible to prevent casing leaks, which in these wells are critical due to their population sensitive location.
Applying a Geologist's Tools to Decipher Scaling History: Integration of Mineralogy, Morphology, and Polymorphic Differentiation
Authors: Lynn Jack D. 
Published: May 2016

Abstract
Commonly, only very limited amounts (10–200 g) of sample can be retrieved by bailers or on the filter screens at well heads and the usual evaluation is simply XRD, XRF and occasionally, SEM analysis to identify basic mineralogy. Unfortunately, these very small and poorly differentiated samples are the only evidence production engineers have to evaluate significant issues with completion and drilling chemistry. But, a geologist's eye, and polymorph chemistry can use these small samples to dictate a story. In a recent study, meticulous sample preparation and visual sample evaluation, combined with XRD, thin section petrography, crystal morphology, and evaluation of polymorphic and formation water chemistry have been intertwined to evaluate scaling history in several wells in a high temperature, high pressure gas condensate field. The study was able to identify various polymorphs of CaCO3, (including Mg-calcite and aragonite), and assign them to quiescent vs. dynamic precipitation regimes, through the assessment of morphological features (including botryoidal, dendritic and flos ferri morphologies of aragonite). In addition, multiple stages of barium sulfate (BaSO4) and sulfate/carbonate co-precipitation were identified. An additional fecarbonate phase, siderite (FeCO3), was identified. Using thin section petrology, mineralogy, and a thorough review of drilling and completion operations, the unique scale formation history of these wells was traced, and issues were identified with long-term post-completion shut-ins while waiting for tie-in of manifolds to pipelines. Issues were identified with CO3 -2 pH buffers in formate based completion and drilling fluid interactions with high calcium formation brine, which migrates to the well bore by ionic diffusion and counter-current imbibition. The identification of this previously un-suspected damage mechanism has led to modification in completion fluid formulations to eliminate future events, and improve post drilling PI on wells drilled in the gas fields in question. It highlighted the requirement for a scale control program which is being developed to be concurrent with new well drilling and completion. Finally, the study highlights the need to evaluate fully the components of drilling, completion and stimulation fluids, both individually, and in combination-To be sure to fully assess the risk of formation damage, even when using a welltested and proven industry fluid. The phrase "doveryai, no proveryai" ("trust, but verify") takes on a new meaning (with due respects to US Pres. R. Regan).
Azimuthal Seismic Inversion for Shale Gas Reservoir Characterisation
Authors: Roure B. , Downton J. , Doyen P.M. , Michel L. , Souvannavong V. 
Published: May 2016

Summary
Azimuthal AVO analysis can be split into two parts: the Amplitude Versus Offset (AVO) analysis and the Amplitude Versus Azimuth (AVAz) analysis. The properties of the Fourier transform allow these problems to be treated separately. If we calculate a Fourier transform of AVAz PP reflectivity data at a particular angle of incidence, we obtain Fourier Coefficients (FCs) that parsimoniously describe the AVAz and anisotropy, similar to the near offset Rüger equation. It is possible to attach physical significance to each of the FCs using simple rock physics models that relate the anisotropy to the fractures. The different FCs may be combined in a non-linear fashion to estimate fundamental fracture parameters including fracture intensity and orientation. The FCs are calculated using a limited range of offsets or angles, which places less demands on the data acquisition. This may be advantageous for 3D land data sets, where near offsets are particularly under sampled. However, reflectivity-based fracture characterization techniques show some limitations in terms of interpretation of the results. These limitations can be removed by using the azimuthal elastic inversion which provides layer properties that are easier to interpret and relate more directly to the geology.

Introduction
Ikelle (1996) and then Sayers and Dean (2001) demonstrated that it is possible to express the azimuthal AVO reflectivity response in terms of a Fourier series as a function of azimuth. Due to the orthogonality of the Fourier transform, these Fourier Coefficients (FCs) represent independent information and may be used in combination or individually to make inferences about fracture-induced seismic anisotropy. Fracture properties can be calculated using just one offset or angle of incidence and we can obtain results similar to those obtained by the near offset Rüger equation using multi-offset/angle data. Combinations of FCs may be used to obtain unbiased estimates of both the anisotropic gradient and the fracture orientation. The FCs and near offset Rüger methods share the same limitation that amplitudes are treated as reflectivities, i.e. the wavelet effect is still part of the solution. Moreover, the estimates are interface properties which are more difficult to relate to the geology than interval properties. To overcome these issues, Downton and Roure (2010) introduced an azimuthal elastic inversion where azimuthal angle stacks are inverted simultaneously. This method was later extended to invert azimuthal Fourier Coefficients (Roure and Downton, 2012). The fracture properties estimated by the elastic inversion can be more easily used for interpretation.
AKPO Condensate Field case study, Nigeria.4D seismic monitoring of a complex deepwater turbidite reservoir.
Authors: Piovesanel E. , Claudel G. , Atewologun A. , Adeyemi A. , Yuh S. 
Published: May 2016

Abstract
This paper addresses the 4D seismic monitoring aspects of AKPO, a complex deepwater field operated by Total Upstream Nigeria Ltd (TUPNI). AKPO development is driven by seismic in many ways. Seismic reservoir characterization is critical for well placement, optimization and monitoring while drilling, as well as to delineate reservoir sedimentology, capture heterogeneities and populate the geological model with rock properties. In addition, time-lapse seismic monitoring plays a key role in the understanding of the field dynamics, the update of the reservoir model and the field management as wells as the planning of the infill campaign. The first results of AKPO 4D monitoring program yield highly valuable information with great impact on reservoir management.
Study and Application of Shallow Water Fracturing Fluid in High Temperature Deep Carbonate Reservoir
Authors: Che Mingguang , Wang Yonghui , Cheng Xingsheng , Lu Yongjun , Li Yongping , Zhang Fuxiang , Peng Jianxin , Zou Keyuan 
Published: May 2016

Abstract
The Taklimakan is the second largest desert in the world; the TaZhong oilfield is located in the Taklimakan Desert heartland.
The Ordovician carbonate is one of the producing zones of TaZhong field. Acid fracturing has been normal for stimulating wells in these carbonate formations. The freshwater prepared for fluid and acid was conveyed 300 kilometers far away from TaZhong oilfield in the early construction, a lot of money and time was spent on transportation. However, there is superficial saltwater at a depth of tens of meters under the desert, and this paper will provide the technology of reducing freshwater consumption by using shallow saltwater for pad fluid in acid-fracturing.
First, this paper presents a brief developed history of TaZhong oilfield and the characteristics of Ordovician formation. In major, this paper introduces the study and case of Taklimakan desert superficial saltwater fracturing fluid, including the shallow water salinity tests and the problems of shallow water fluid, solutions for stable fluid and the performances of superficial saltwater fluid, such as the stability of saltwater fluid, rheology, and gel breaking and injures. Final, a field example of acid fracturing used shallow water fluid is included, and the responses of treating pressure are analyzed.
This work has helped prove the shallow saltwater in the desert of TaZhong oilfield which is feasible for service in acid-fracturing treatment oprations, a result has been established that a reliable fracturing fluid with good performance is wide used recent years. Because of the technology of superficial water fracturing fluid, an acid fracturing treatment well time saving is 2 to 3 days, and the transportation cost saving was considerable.

Introduction
The depth of the Ordovician formations is 4000m-6000m, and the temperature is from 110? to 150?. The natural fissures and vugs are major hydrocarbon reservoirs because of the low matrix porosity (2%-5%) and low permeability. Acid-fracturing is the main stimulating treatment in TaZhong carbonate, such as pad acid fracturing or multi-alterenative acid fracturing. Water based hydroxipropil guar fluids are generally used for preflush, and several acids are applied during treatment, such as gel acid, surface-crosslinked acid, emulsified acid and VES acid. Recent years, further development of the field had been achieved with well stimulations, increasing production rates, over a hurdred of wells were treated by acid fracturing and more than twenty wells were treated by hydraulic fracturing or sand fracturing with surface-crosslinked acid. This has led to increase freshwater consumption for these oprations, in order to save freshwater sources and conveyance costs, the field employers have to find alternatives to reduce the fresh water consumed, the shallow saltwater under the Taklimakan desert is considered.