bluuebunny/crossref_metadata_2025_split huggingface dataset:
Utilisation of Lasers in Petroleum Drilling Industry
Authors: Bazargan M. , Madani A. , Sharifi H. , Jalalyfar H. , Ghassemal askary K. , Rostamian A. 
Published: May 2016

Abstract:
Due to constructive role of technology developments in petroleum industry and their affects in reducing the costs of drilling, it is necessary to use future technologies. One of these new progresses taking very effective role in drilling industry is to get use of laser in drilling processes. The aim of this paper is to categorize and represent the different study results and also to analysis the principle and advantages of laser drilling. Compared to prevalent drilling, laser drilling is capable to augment the efficiency of drilling and solve its problems such as increasing the rate of penetration, monitoring the bottom hole, diminishing equipment and drilling process, but faces some problems such as laser beam transference, cleaning the down hole. As a result, the benefits of laser drilling overcome the problems and it can be replaced or combined in bits in early future. in this paper we showed the result of using laser technology during drilling operation. Also, In this paper we experiments on changing wavelength transmitted during fracturing and drilling.
Petrophysical Seismic Inversion Over an Offshore Carbonate Field
Authors: Souvannavong Vimol , Allo Fabien , Coleou Thierry , Colnard Olivier , Machecler Ingrind , Dillon Lucia , Schwedersky Neto Guenther , Nunes Cassiane , De Abreu Elita , Colpaert Arnout , van Wijngaarden Aart-Jan 
Published: May 2016

Abstract
The main objective of this project was to evaluate the ability to derive petrophysical properties like porosity from pre-stack seismic data in a carbonate environment. We apply a direct petrophysical inversion technique to an offshore carbonate reservoir. Starting from an initial geological model in depth and a number of carefully conditioned seismic angle stacks, we derive a detailed 3-D model of the porosity and hydrocarbon saturation matching the observed seismic data. We use a well-calibrated Petro-Elastic Model (PEM) to link the petrophysical properties to the seismic velocities. We compare inversion results obtained using the Xu-Payne and T-matrix PEMs which both account for carbonate pore geometry, lithology, porosity and fluid content but have different elastic sensitivity to fluid saturations. The inverted results provide detailed images of the spatial variations of porosity and fluid content across the reservoir interval. Obtaining estimates of absolute saturations values is more difficult, as saturation estimation is strongly dependent on the choice of PEM.

Introduction
Carbonate reservoirs are notoriously heterogeneous. Seismic inversion is therefore needed to help estimate the spatial variations of rock type, porosity and fluid content in between the available wells. We present the results of a direct inversion of porosity and saturations from seismic pre-stack data over an offshore carbonate reservoir.
Intensive Use of 4D Seismic in Reservoir Monitoring, Modelling and Management: The Dalia Case Study
Authors: Pluchery E. , Toinet S. , Cruz P. , Camoin A. , Franco J. 
Published: May 2016

Introduction
Born nearly thirty years ago, time lapse (4D) seismic monitoring technology has been developed in some cases to monitor fluid movement and to distinguish between drained and un-drained portions of a reservoir. It allows quantitatively improving reservoir models, particularly their predictive capability. Indeed, the benefits of time-lapse seismic for reservoir characterization depend on the quality of 4D acquisition and processing, but they also greatly depend on the particular 4D inversion and interpretation methods used. Finally, a decisive aspect is certainly the capability of integrating results from different disciplines in an effective way. Timing is also crucial: results delivered in a few months can have a direct operational impact such as field monitoring or well location and design optimization.
For the last ten years, Total has recognized the importance of time lapse seismic and has therefore conducted 4D seismic monitoring in different geological environments. Examples of 4D experiences range from monitoring of water injection and production for complex reservoir management and field development in the Gulf of Guinea (Angola and Nigeria); monitoring of geomechanical effects in HPHT fields (Elgin-Franklin, UK), in compacting reservoirs in Norway (Ekofisk and Valhall) and in the Gulf of Mexico (Matterhorn, US); monitoring of steam chamber in tar sands (Surmont, Canada) and monitoring of compaction and water rise in carbonates (South-East Asia). This paper focuses on the intense use of 4D seismic on the DALIA Field (Angola, Block 17).
A New Method to Interpret Hydraulic Fracture Complexity in Unconventional Reservoir by Tilt Magnitude
Authors: Wang Xin , Ding Yun Hong , Xiu Nai Ling , Wang Zhen Duo , Yan Yu Zhong 
Published: May 2016

Abstract
Hydraulic fractures in unconventional reservoir are complex. Surface tilemeter fracture mapping method is used to obtain ground deformation field caused by hydraulic fracture. The observed and theoretical fracture-induced tilt vectors from a best-fit fracture solution are compared and obtain hydraulic fracture orientation and shape. Through analysis of the vertical and horizontal component volume, three new parameters are given to characterize the fracture complexity, i.e. ratio of fluid volume to fracture volume R; volume weight difference rate D and fracture complexity index ß. These new parameters are used to explain the mapping result of shale and coal seam reservoir. The results show that R of coal bed and shale is 2.2 and 2.9 while sandstone is only 1.4. ß of shale, coal bed and sandstone are 0.7,0.4 and 0.3 respectively, the two new parameters show hydraulic fractures in unconventional reservoir are very complex. The new parameters can describe fracture complexity very well, and results are correlated well with the results of fracturing pressure analysis and other methods of monitoring. This method provides valuable information for optimizing fracturing treatment design and postfrac evaluation in unconventional reservoir.
Experimental Investigation of Hydraulic Fracture Propagation in Acoustic Monitoring Inside a Large-Scale Polyaxial Test
Authors: Liu Yuzhang , Cui Mingyue , Ding Yunhong , Peng Yi , Fu Haifeng , Lu Yongjun , Liu Yunzhi 
Published: May 2016

Abstract
Field experiences suggest significant interaction between natural fractures and hydraulic fractures in unconventional reservoir and some tight gas sandstone. Microseismic monitoring is a widely used methodology to understand the real-time evolution of fracture geometry during hydraulic fracturing, which is essential for evaluating the SRV under certain treatment, especially in unconventional reservoir. Howerver, the correlation between the real fracture geometry and microseismic monitoring results is still open to discuss. Therefore, understanding the relationships between the induced fractures and acoustic emission in different laboratory conditions is of high importance for studying the mechanism of hydraulic fracturing and ultimately optimizing fracture complexity.
A large polyaxial testing system was built for investigating the factors of inducing complex fractures in sandstones, shale and coal for hydraulic fracturing treatment. This paper presents the experimental results of a study conducted to understand the mechanism of fracture initiation and propagation based on acoustic emission monitoring. Large-scale test was conducted in dry sandstone outcrop of 762×762×914mm to simulate the hydraulic fracturing. True triaxial stresses were applied to the specimen. The acoustic emission events associated with fracture propagation or failure process during injection were monitored to provide further data to characterize the fracture. The hydraulic fractures and oil penetration surface were observed after injection.
Results show that the acoustic emission monitoring is in good accordance with the split block surface dyed red. AE localizations clearly demonstrate fracture initiation and propagation dynamics in the sample which can be used to control the fracture. The AE rates increased with opening hydraulically induced fracture and its closure. The real-time fracture geometry can be calculated by integrating the borehole pressure, AE localizations, injection rate, fluid leakage and rock mechanical properties. We are currently investigating various ways for building the fracture propagation model. The work presented here a new hydraulic fracturing testing system integrated with geophysical monitoring and processing technologies that will improve laboratory study of hydraulic fracturing mechanism and provide a trial on new ideas and technology
Factors Controlling Recovery in Liquids Rich Unconventional Systems
Authors: Wan J. , Barnum R.S. , Digloria D.C. , Leahy-Dios A. , Missman R. , Hemphill J. 
Published: May 2016

Abstract
According to the U.S. Energy Information Administration (EIA), oil production in the United States reached 6.68 million barrels a day in November, 2012, its highest level since 1994. Development of hydrocarbons in deep unconventional formations via horizontal drilling and fracturing has been the main contributor to this growth. The two most impactful plays have been Bakken in North Dakota and Eagle Ford in Texas. While recognizing the success of unconventionals associated with high oil price and enhanced hydraulic fracture stimulation technologies, it is important to understand the development challenges and factors controlling recovery. The combination of limited drainage area and low resource density in unconventional systems has led to low recovery per well and challenging economics. Unconventional development has increasingly focused on liquids rich systems, especially in North America due to relatively low natural gas prices. The addition of liquids can improve overall economics, athough two phase flow impacts and complicates fluid flow and ultimate recovery. Performance of liquids rich systems is highly dependent on in-place fluid composition and phase behavior. Therefore, understanding liquids rich system phase behavior and its impact on performance is an important economic consideration. This paper discusses the drive mechanisms for unconventional plays ranging from dry gas to oil and the importance of geology and rock and fluid properties on rate and recovery. It specifically explores how the variation in liquid yield impacts rate and recovery.

Introduction
Unconventional development has increasingly focused on liquids rich systems in recent years, especially in North America, due to relatively low natural gas prices. In order to efficiently explore, appraise, develop and produce liquids rich unconventional reservoirs, it is important to understand their key characteristics. Due to low porosity, shales typically have low net hydrocarbon pore thickness and resource density. Low matrix permeability limits productivity and drainage area. These geologic constraints are countered with hydraulic fracturing, which is critical to achieving larger drainage areas and economic rates and recoveries. Liquids rich unconventional plays are also significantly impacted by large pressure gradients in the near wellbore area and by variations in rock and fluid properties. In recent years, significant progress has been made in understanding geological, petrophysical, rock and fluid characterization of unconventional plays, as well as their impact on production [1–4]. This paper provides an overview of the key factors controlling production from liquids rich unconventional plays, particularly the impact of pressure, pressure gradients, and fluid properties. Numerical and field examples are included.
Reaction Transport Modelling (rtm) in the Prediction of Dolomitisation Distribution in Carbonate Reservoirs.
Authors: Ronchi Paola , Consonni Alberto , Borromeo Ornella , Battistelli Alfredo , Geloni Claudio 
Published: May 2016

Abstract
The application of Reaction Transport Modelling to cases of dolomitization allows testing the genetic interpretation and may help in predicting the lateral extension of the dolomite hydrocarbon reservoir in the subsurface. The results of numerical diagenetic modelling simulations of four different dolomitization processes are presented. In all the cases the simulations suggest that the hydrogeologic system is the most important driver for dolomitization: in fact the final geometry of dolomite bodies is greatly affected by the permeability field and presence of fractured zones.

Intoduction and methods
The dolomitization processes produce alterations in the pore network system of carbonate bodies from deposition to deep burial (Machel, 2004); therefore the comprehension and the distribution prediction of the processes and their product is of paramount importance in hydrocarbon research both in explorative and development phases. A well constrained diagenetic interpretation allows assumptions to be made about the distribution of the dolomitized bodies in the subsurface. The new approach in diagenetic studies is to integrate the classical investigative techniques with the reactive transport modelling (RTM) in order to better define the conceptual models in terms of mass balance, kinetic and thermodynamic constraints (Whitaker et al., 2004). The numerical modelling applied to carbonate diagenetic systems is a fast growing discipline in the petroleum industry for its help in prediction of the extension of the diagenetic processes and related changes in petrophysical properties. Four different dolomitization models have been simulated using a sensitivity analysis approach in order to strengthen the conceptual interpretation and to evaluate the main constraints of each dolomitization process. The RTM was performed using the TOUGHREACT code (Xu et al., 2004); in this code the geochemical reactive transport is coupled to the TOUGH2 framework of multi-phase fluid and heat flow. The code calculates rock/water system evolution through the simulation of brine flux in a porous media, transport of chemical species in water solution and mineral/fluid reactions. The simulator can be applied to 1-, 2-, or 3-dimensional unstructured domains with physical and chemical heterogeneities. The first parameter to be simulated in a dolomitization reconstruction is the fluid flow into the rock. In the cases of synsedimentary dolomitization the amount and rate of fluid flow is the result of the chemio-physical conditions, for example in the reflux dolomitization the fluid flow is the direct consequence of fluid density in the system; in the dolomitization cases in which the fluid flow is linked to processes external to the area under simulation, for example in compaction dolomitization model, the evaluation of fluid flow amount and rate is to be simulated using a basin simulator (SEBE, Eni proprietory coftware).
Multi-Phase (Oil-Water) Loop Flow Test for Helical and Hybrid Passive Inflow Control Devices
Authors: Lee Byung O. , Rabeh Majed N. , Vicario Roberto , Gavioli Paolo , Garcia Gonzalo 
Published: May 2016

Abstract
To address the need for better understanding of multiphase fluid flow behavior through passive inflow control devices (PICDs), two-phase (oil-water) full-scale flow loop testing on helical and a new ICD design, "Hybrid" has been completed. The primary testing objective was to generate a comprehensive two-phase (oil-water) data set of flow performance curves for the helical ICD and the hybrid ICD. The test included a broad range of flow tests with varying viscosities, water cuts and pressures. The results are presented in an innovative manner using isobaric plots (isobars lines with trend lines for each viscosity value) and Reynolds number vs. Flow Coefficient plots, which can be used to easily compare different ICD performances. Test results confirm that for oil-water flow, a viscosity break point for the helical ICD occurs at 2 centipoise (cP) of medium oil. Below this break point the helical ICD does not promote water production in two-phase flow. Above this viscosity break point, the helical ICD exhibits a physical phenomenon where, at water cuts above 30%, the total flow increases at any given pressure drop promoting water flow. With regards to two-phase oil-water fluid flow, the hybrid ICD performs independently of viscosity for the range tested (up to 200 cP - maximum flow viscosity tested at the lab).The hybrid ICD consistently creates more resistance to water flow than to oil flow, causing total flow to gradually decrease at constant pressure as water cut increases. This effect was more apparent at higher pressure regimes. The functional break point of the hybrid ICD is determined to be above 200 cP.

Introduction
A comprehensive two-phase (oil-water) data set of flow performance curves for the helix inflow control devices (ICDs) and hybrid ICDs was conducted through extensive laboratory testing to identify the threshold viscosity, and to quantify single and multiphase model validity. These test results confirm that the threshold viscosity is 2 centipoise (cP). At viscosities greater than 2 cP, the test results confirm previously published findings that the helix design exhibits preferential production of water for a given pressure drop in a two-phase flow. Additionally, results verify that the helix ICD behavior exhibits correlation to the single phase model but requires a correction due to non-constant flow coefficient, and does not exhibit correlation when the fluids are multiphase, especially at higher viscosities.
Coalbed Methane Modelling Best Practices
Authors: Philpot Jared Anthony , Mazumder Saikat , Naicker Siddharta , Chang Gladys , Boostani Mohammad , Tovar Miguel , Sharma Vikram 
Published: May 2016

Abstract
Determining the potential range of recoverable volumes for a Coalbed Methane (CBM) prospect is a necessary precursor to a successful development plan. Several key best practices were incorporated into a workflow to consistently assess the CBM potential of numerous prospective areas.
For each area 3D static models were built based on available structural data. The models were geo-statistically populated with coal properties such as density and ash content. Correlations for other properties including gas content, permeability and Langmuir volume were developed. An analysis of the residual distribution between each correlation and its measurements was used to characterise the uncertainty in each. Several methods were considered to reproduce this uncertainty. These ranged from directly applying discrete trends, to geo-statistical property population. The effect of applying each on the predicted EUR was investigated.
Reservoir simulation models of production pilots were built and history matched. Given the complexities of the coal reservoir and the non-uniqueness of the history match, further work was carried out to capture the remaining uncertainty and determine its impact on the model predictions. Experimental design (DOE) was used to generate a population of simulation models that sampled the uncertainty range. By using the measured pilot production as a filter, this population was reduced to include only those that matched the observed production.
The final step was to optimise the placement of development wells. An algorithm that traded off the gain in gas recovery obtained by a tighter well spacing, against the increased cost associated with the extra wells was devised. The uncertainty in recovery given by this well spacing was tested using the reservoir simulation models.
Although static and dynamic modelling of CBM reservoirs is quickly becoming routine in the industry, the best practices developed while building this workflow are novel solutions to several challenges that still confound the CBM modelling community. These best practices are not unique to the study area and could easily be applied to other areas. As such this paper should provide a useful reference to those about to undertake a CBM modelling project.
Extended Use of S13Cr Materials for Downhole Production Tubing
Authors: Lee R. , Bol J.E. 
Published: May 2016

Abstract
Historically, martensitic stainless steels (13Cr or Super 13Cr) are known to provide a high strength, corrosion resistant production tubing material for sweet (CO2) corrosion service. The material is generally considered to be susceptible to Sulphide Stress Cracking (SSC) in sour (H2S) production environments. However, the combination of pH, temperature and chloride levels plays a significant role in altering the behaviour of this material under sour conditions. pH is commonly known to be affected by factors such as bicarbonate buffering, the presence of carbon dioxide and acids. The "self-healing" rate of chromium oxide of stainless steels is dependent upon the environment to which it is exposed, affecting its resistance to SSC.
By understanding the overall service conditions and testing the martensitic stainless steels material(s) accordingly, the use of this material has been made possible beyond commonly accepted limits without compromising its overall properties. Specific testing (cyclic slow strain rate tests), more onerous than that recommended by NACE, has been conducted for the qualification of identified martensitic stainless steels. The test regime covered both production and shut-in conditions. The results show that under the particular conditions, S13Cr materials cracking resistance differs from the limitations described by NACE MR0175/ ISO 15156.
This paper aims to highlight business cases that have led to specific testing of martensitic stainless steel and describes the significant cost savings that have been achieved by using S13Cr materials as production tubing in sour service.
Application of the Multi-Parameter Geostatistical Inversion in the Carbonate Reservoir Prediction
Authors: Liu Cai Qin , Wang Zhao Feng , Wei Xiao Dong , Zhang Da Wei , Peng Bo , Xin Chen , Peng Bo , Yang Ke 
Published: May 2016

Abstract
Four lithologies were developed in the study area and they were pore-bearing grainstone, compact sparite, shaly limestone and limy mudstone. The pore-bearing grainstone was the main reservoir rock. The characteristic analysis of the electrical and physical properties showed that the acoustic impedance of the pore-bearing grainstone was medium to relatively low. If we only use the inversion data of acoustic impedance, it is difficult to distinguish between the pore-bearing grainstone and other lithologies. In addition, it is difficult to distinguish the reservoir using any single given electrical parameter such as GR, density and resistivity. Therefore, we selected several sensitive logging parameters through crossplot analysis. On the basis of the geostatistical inversion, several volume data were combined, thereby the favorable reservoirs were determined.
The multi-parameter geostatistical inversion integrated and constrained by logging data and seismic data. It not only takes the advantage of the geostatistical inversion which does not simply use the acoustic impedance to joins the calculation, but it also uses the curves such as GR, porosity which directly reflect the lithology and physical properties of the formation, to join the calculation. Compared with the conventional acoustic inversion, it greatly improved the vertical resolution, finely characterized the distribution of the reservoirs, and better conquered the problem of the multiplicity of the reservoir prediction and resolution?