bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterization and Development of Deep Carbonaceous Shales: A North Kuwait Case Study
Authors: Al-Arouj M. A. , Barasia A. , Fidan E. , Darous C. , Sharma S. S. , Al-Mutairi M. D. 
Published: May 2015

Abstract

Objectives/Scope
Unconventional organic-rich carbonaceous shale (OCS) in North Kuwait has unique characteristics due to its high total organic content (12–14%), its complex mineralogy (blend of carbonates and clastics) and Jurassic/post-Jurassic complex burial and tectonic history. The OCS is under/over-laid by tight carbonates, where the system permeability is in the range of nano to micro-Darcy. Conventional techniques to initiate flow from this complex reservoir have proven ineffective, which led the appraisal team to develop novel and extensive workflows to characterize the formation properties for successful hydraulic fracturing and to determine the commercial flow potential of hydrocarbons.

Methods, Procedures, Process
Three vertical wells were identified as the high potential candidates in the appraisal program, prior to the completion of horizontals in this complex formation. A comprehensive logging suite was acquired which included spectroscopy, sonic and image logs. Fracture pressure analysis was performed on an offset well followed by exhaustive diagnostic tests using both non-viscous and viscous fluids. Bottom hole gauges were hanged in the well during the diagnostic tests as well as temperature logging was performed after the diagnostic pumping to define fracture height growth/containment. Proppant fracturing in these wells are planned using nonradioactive tracer proppant.

Results, Observations, Conclusions
Maximum clay content in the OCS is estimated close to 40% in addition to the high organic content. Anisotropic mechanical earth model was built using sonic log response for fracture modelling in planar 3-D simulators. Some open fractures were observed from the image logs. Fracture pressure analysis on the offset well confirmed “fraccability” of the OCS within the allowable pressure limits. Analysis of the diagnostic tests confirmed significant impact of natural fracture on hydraulic fracture propagation. Nolte-Smith plot using actual bottom-hole pressure revealed very high net pressure slope during viscous fluid stages that raised significant concerns on possibility of placing proppant. Interventions after the diagnostic tests showed flowback of formation material in the form of “formation creep” into the wellbore and that lead to concerns on formation integrity and risks in proppant placement.

Novel/Additive Information
This paper discusses various methods used to understand the complex OCS formation and integrates extensive analysis achieved through different methods. Interpretation of this data-set and building a model which will be used for development of future horizontal wells will also be presented. It is believed that the inherent challenges presented by the OCS are unique without any true global analogues in the unconventional gas and oil programs.
How to Determine True Acid Diffusion Coefficient to Optimize Formation Damage Treatment?
Authors: Qiu Xiangdong , Khalid Muhammad Ali , Sultan Abullah 
Published: May 2015

Abstract
Diffusion Coefficient (De) is a very important parameter for the formation damage treatment job design. Commonly a Rotating Disk Apparatus (RDA) is used to obtain acid De and reaction rate. There are two major limitations of conventional lab practices (1) The De is obtained at 1000 psi (or below) system pressure, which is too low to represent realistic reservoir conditions. (2)The De obtained from lab experiments are based on a fresh acid, which has been ignoring the impact of reaction products, especially CO2. Hence the results of De cannot represent the real reaction kinetics between carbonate rock and injected HCl during the acid treatment.
In this paper, we investigate the effects of De of HCl acid as it reacts with both calcite and dolomite. A modified RDA is used to obtain the true spent acid reaction kinetics at reservoir conditions. In order to provide accurate reaction kinetics data that is more representative of the true reservoir conditions, a true spent acid concept is adopted here in this study. The true spent acid is formulated at reservoir condition in various spending stages. In addition, different mineralogy including calcite and dolomite are fully studied. The reaction products of CO2 and counter ions are taken into consideration at different acid spending stages.
The experimental results show that the De of the HCl acid is much lower at high pressure than low pressure at the same concentration due to the impact of CO2 produced by the HCl-carbonate reaction. For example, at 150 °F, the diffusion coefficient of 15% HCl at 3,000 psi reduced 50% of its original value when at 1,000 psi of 15% HCl. The diffusion coefficient of the fresh acid is much higher than the diffusion coefficient of the same acid strength of true spent acid due to the presented count ion and CO2 in the true spent acid. The De of HCl/calcite is two orders of magnitude higher than De of HCl/dolomite at the same conditions (acid concentration, temperature).
Conventional experimental results significantly overestimate the De, dissolution rate and reaction rate. When the De implemented in a job (formation damage treatment) design, those defective data could result in dramatic errors in determining the treatment fluid schedule, rate, and volume. In order to properly design the formation damage treatment jobs, the De of acid acquired from high-pressure and various spent conditions should be used.
Formation Damage Diagnosis Facilitates a Successful Remedial Treatment Design and Execution in Sandstone Horizontal Oil Producer: A Laboratory and Field Case Study
Authors: Bataweel M. A. , Al-Ghamdi A. H. , Osode P. I. , Almubarak T. A. , Azizi E. S. , Sarhan Eddy , Al-Faifi M. G. 
Published: May 2015

Abstract
Well-control fluids were used during a routine overbalanced workover operation in an offshore well completed in high permeability sandstone. As expected, a fluid loss control pill was used to control the excessive losses encountered during this operation. However, due to the high permeability of the reservoir and the absence of sized particles in the pumped pill; large amount of fluids were lost to the formation before losses were controlled. The deep invasion of fluids laden with high concentration of polymer had inevitably resulted in severe formation damage and impaired production. Several attempts to clean out the wellbore and revive the well flow were unsuccessful with no injectivity either. The well was consequently suspended while a multidisciplinary team was formed to identify the cause of the impairment and recommend a treatment plan.
A comprehensive review of detailed field operation and data related to the fluid losses accompanied with laboratory work to identify the damaging mechanism and formulate an optimized remedial treatment was conducted. The lab work included jar testing to assess compatibility and emulsion tendency when different wellbore fluids are mixed with each other and with formation fluids. Analysis of the samples collected from the wellbore was carried out and different treatment fluid options were evaluated using actual field samples. Core flood experiments were also conducted to assess the impact of high-viscosity pills on permeability and ability of remedial treatment in restoring the original permeability.
Experimental results revealed partial removal of the polymer invading the core using organic acid. The designed pre-flush composed of mutual solvent with surfactant package was effective in breaking the emulsion from field samples and laboratory-prepared emulsions. A significant improvement in production from this well was realized by application of a cost effective formic acid-based chemical treatment. Proper treatment design with effective displacement technique were also attributed to the successful damage removal and regained well productivity.
A Fast Simulation Tool for Evaluation of Novel Well Stimulation Techniques for Tight Gas Reservoirs
Authors: Egberts P.J.P. , Peters E. 
Published: May 2015

Abstract
For stimulation of tight fields, alternatives to hydraulic fracturing based on hydraulic jetting are becoming available. With hydraulic jetting many (10 to 20) laterals can be created in a (sub-) vertical well. The laterals are 100 to 200 m long, typically 4 laterals are applied with a small inclination at a single kickoff depth. This type of well configuration will be called a radial well. A simulation tool based on a semi-analytical method is developed to computate the production performance of a radial well. The tool provides an efficient way to assess the production potential of a stimulated well for many different well designs. The method is particularly suitable for performing a sensitivity analysis to preselect a limited number of designs to be further analysed. The results of the tool show excellent agreement with those of a numerical reservoir simulator. As an example, the tool is applied to a stacked field with three separate reservoirs, wich have permeability ranging from 1 to 5 mD. The radial well increases cumulative gas production by 10% for the reservoir with 5 mD and by 50-70% for the reservoirs with 1 mD permeability.
A Better Formulation of Objective Functions for History Matching Using Hausdorff Distances
Authors: Bouzarkouna Z. , Nobakht B. Nezhad 
Published: May 2015

Abstract
History matching aims at finding one or several reservoir models that closely reproduce the past behavior of the reservoir. Objective functions are often used to measure the quality of these models.
Indeed when using assisted history matching techniques, a good formulation of the objective function is crucial since it increases the likelihood to get an acceptable history match. Moreover, for manual history matching, and in particular for large fields, objective functions can also be used in order to compare between runs and to help understanding the field.
In this paper, we investigate an alternative new formulation of the objective function. The proposed formulation does not take into account only the difference between the production data (point by point) but also discrepancies in the shape. The proposed formulation is based on an appropriate Hausdorff distance.
The proposed approach is applied on different data from different real history matching studies. Results are compared with the standard mean squared error formulation, and shown to satisfy more reservoir engineering principles when comparing between runs.
Life of Field Reservoir Surveillance and Optimization Using Cased-Hole Log Measurements
Authors: Kaawan Emad , Juha Lutfi , Elmanghush Aziza 
Published: May 2015

Abstract
Reservoir management is about optimizing reservoir performance to achieve long-term recovery goals. This can be accomplished through a systematic application of integrated, multidisciplinary technologies to positively impact financial performance and achieve synergy. Multidisciplinary integration leads to better understanding of reservoir performance for proper decisions on remedial actions such as water shut-off, additional perforations, stimulation; for long-term planning and enhanced oil recovery to optimize production at the well and field levels. The case of the As-Sarah field in Libya shows how cased-hole logging and production-monitoring contributed to successful reservoir management.
Cased-hole production and pulsed-neutron-logging have been used extensively since the early life of As-Sarah field for reservoir surveillance and to identify opportunities for remedial actions. A significant number of thermal--decay-time, reservoir saturation and production logging campaigns have been performed. The aims of these campaigns were to estimate the propagation of the oil/water contact (OWC), determine the residual oil saturation profile, identify watered-out zones for isolation, and define zonal contribution. A re-interpretation project of all As-Sarah field cased-hole logs was completed and presented in a comprehensive time-lapse display. The results of this project guided the fluids movement during history-matching in the dynamic model.
Using reservoir saturation measurements along with the production logging data ensured data consistency and reliability. This helped the operator to be certain that there was no movable-oil left in the formation, enabling confidence in the decision to plug-back the water-entry zones. This integration was used for tar-mats mapping, characterization of the low-productivity D and E units at the top of the reservoir, re-evaluating the recovery factor, and anticipating the OWC for infill-well planning.
Building time-lapse water saturation and flow profiles is not straightforward. The water and remaining oil saturations must be calculated for each well to evaluate the fluids' mobility. The project included detailed saturation processing taking into account the field-wide reservoir residual oil saturation. Presenting the results in this unique format provides quick and easy access to a huge amount of data, thus providing an at-a-glance understanding of the reservoir behavior and aquifer strength. It also contributed to optimizing liquids' off-take, minimizing bypassed reserves and selecting wells for further monitoring. The log results were correlated with production history to calibrate and validate the dynamic model that is being used for field development.
Solar Generated Steam Injection in Hamca, Venezuelan Extra Heavy Oil Reservoir; Simulation Study for Oil Recovery Performance, Economical and Environmental Feasibilities
Authors: Yegane Mohsen Mirzaie , Ayatollahi Shahab , Bashtani Farzad , Romero C. 
Published: May 2015

Abstract
Application of solar energy compared to conventional gas-burning boilers for steam generation in thermal Enhanced Oil Recovery processes is a newly attended technology, which brings significant benefits to the petroleum industry through environmental and economical aspects. This technique is especially designed for the regions in which gas-burning steam generation is not viable in large scale. The objective of this study is to investigate about viability of using solar energy to generate steam instead of using conventional steam generators in a Venezuelan extra heavy oil reservoir. Limited gas production policy of the Venezuelan government is the major challenge for utilizing gas steam generators for extra heavy oil reservoirs in this country. Besides, the efficient daylight duration, economic and environmental advantages, are the main features to propose solar-generated-steam injection in Venezuelan extra heavy oil reservoirs. In this study, various scenarios of steam injection on Hamaca-Venezuelan heavy oil reservoir-have been investigated using commercial thermal simulator software and the main results of oil production for similar time periods (5 years) are compared. To compensate the energy needed for the steam generators during the night time, dual types steam generators were proposed to utilize solar and fossil energies during day-time and night time respectively. The simulation results for this extra heavy oil reservoir indicated that the oil production was not significantly improved when solar method is used regardless of the amount of the nightly injection of fossil-fuel generated steam for flow back prevention. This finding illustrated high economic efficiency for solar-generated steam injection compared to dual type (solar and fossil-fuel) steam generator method. Furthermore, the results indicated that in typical imposed cyclic steam injections in integrated solar thermal projects, there is no significant difference in oil productions in various scenarios with different pattern and rate of steam injection if the total amount of injected steam is constant. In addition, this study shows the significant reduction of CO2 and Sulfur Oxides emissions if this new technology is implemented. Besides, various scenarios (with and without natural gas backup) were designed for exact day light duration profile in vicinity of the reservoir in order to optimize the oil production as well as accurate economic and environmental evaluation for each scenario.
Novel Integrated Approach Simultaneously Optimising AFI Locations Plus Number and (A)ICD Sizes
Authors: Dowlatabad Mojtaba Moradi 
Published: May 2015

Abstract
The optimal design of Advanced Well Completions (AWCs) is an important step in field development planning nowadays. However, determination of optimum design of (Autonomous) Inflow Control Devices [(A)ICDs] and their integration with Annular Flow Isolations (AFIs) in an advanced well completed across a heterogeneous reservoir is a challenge which has not been addressed properly yet. Most used, variable strength (A)ICD completion design, workflows by industry are based on trial and error evaluations of a static well-reservoir models. Several researchers also suggested relating the strengths of the devices to near wellbore static reservoir properties such as permeability of the encountering layers. Both of these approaches do not capture the dynamic interactions between the well and constantly changing reservoir conditions. Moreover, neglecting mutual dependency of AFI location and (A)ICD design in the traditionally step-by-step (A)ICD-AFI design workflows, may result in a design delivering low overall productivity throughout the field life.
A novel, integrated (A)ICD-AFI completion design workflow is presented in this paper. The workflow simultaneously optimises (A)ICDs strengths and number plus locations of AFIs in the horizontal and/or multilateral wells based on field's production lifetime. The approach includes stochastic optimisation algorithm coupled with a reservoir simulator and an in-house completion design programming code. The code is developed to automatically generate various (A)ICD-AFI completion configurations required to determine the optimum completion design while honouring practical concerns and economics. A novel AFI modelling technique developed allows integration of AFIs in the optimisation process.
The application of the new and the traditional workflows are illustrated using heterogeneous reservoir simulation models. A significant improvement in total oil production for the wells, designed by the new workflow, was achieved comparing with the wells designed by the traditional workflows. The study aims to help well engineers in designing optimal advanced well completion delivering maximum possible field's added-value.
A New Bayesian Approach for Analogs Evaluation in Advanced EOR Screening
Authors: Siena Martina , Milano Politecnico di , Guadagnini Alberto , Rossa Ernesto Della , Lamberti Andrea , Masserano Franco , Rotondi Marco 
Published: May 2015

Abstract
We present and test a new screening methodology to discriminate amongst alternative and competing Enhanced Oil Recovery (EOR) techniques to be considered for a given reservoir. Our work is motivated by the observation that, even if a considerable variety of EOR techniques have been successfully applied to extend oilfield production and lifetime, an EOR project requires extensive laboratory and pilot tests prior to field-wide implementation and preliminary assessment of EOR potential in a reservoir is critical in the decision-making process. Since similar EOR techniques may be successful in fields sharing some global features, as basic discrimination criteria we consider fluid (density and viscosity) and reservoir formation (porosity, permeability, depth and temperature) properties. Our approach is observation-driven and grounded on an exhaustive data-base which we compile upon considering worldwide EOR field experiences. A preliminary reduction of the dimensionality of the parameter space over which EOR projects are classified is accomplished through Principal Component Analysis (PCA). A screening of target analogs is then obtained by classification of documented EOR projects through a Bayesian clustering algorithm. Considering the cluster which comprises the EOR field under evaluation, an inter-cluster refinement is then accomplished by ordering cluster components on the basis of a weighted Euclidean distance from the target field in the (multidimensional) parameter space. Distinctive features of our methodology are that (a) all screening analyses are performed on the database projected onto the space of principal components, and (b) the fraction of variance associated with each principal component is taken as weight of the Euclidean distance we determine. As a test bed, we apply our approach on three fields operated by eni. These include light, medium and heavy-oil reservoirs, where Gas, Chemical and Thermal EOR projects have been respectively proposed. Our results are (a) conducive to the compilation of a broad and extensively usable data-base of EOR settings and (b) consistent with the field observations related to the three tested and already planned/implemented EOR methodologies, thus demonstrating the effectiveness of our approach.
Evaluation of Petrophysical and Mechanical Features for Shale Gas Reservoirs in South Sichuan Basin, China
Authors: Zhang Rui , Ning Zhengfu , Yang Feng , Zhao Huawei 
Published: May 2015

Abstract
Shale gas, as an unconventional resource, has become an exploration and exploitation hotpoint in China. In this paper, a series of experiments were conducted to investigate petrophysical and mechanical properties on the gas shales in Longmaxi Formation south Sichuan Basin, China. Mineralogical and organic geochemical analysis results indicate shale matrix shows strong heterogeneity and structure complexity. A positive correlation between TOC and quartz indicates that bioclastics are the main source of both siliciclastic and organic matters in anaerobic environment. Pore structure was investigated by mercury injection and nitrogen adsorption measurements. The dominant pore size distributes below 3.7nm measured by mercury injection, while 3-5nm by nitrogen adsorption. Micronsized fractures and nanopore structure of shale samples had been identified through mercury saturation curves and adsorption-desorption isotherms. The average maximum mercury saturation is less than 50% at 414MPa, and all of the nanopores were slit-shaped (Type H3 adsorption-desorption isotherms). The BET specific surface area which was calculated from nitrogen adsorption ranges between 7-19 m2/g and have an obvious positive relationship with TOC (total organic matter content) and illite-montmorillonite mixed layer content. Pulse decay measurement reveals that an exponential function can describe the permeability deterioration upon applied effective stress. The stress-dependent permeability of shale is more sensitive than sandstone because of high pore compressibility (low aspect ratio of pore and elastic moduli). The stress-dependent permeability data of samples with micronsized fractures can also be excellently fitted by Walsh model (fractured porous media permeability model), and fitting results show that the fractures in shale samples have high roughness and small aperture compared with sandstone. Static Young's modulus of shale samples increase with increasing quartz, and decrease with increasing TOC and clay minerals content. Due to the weak mechanical property of montmorillonite, shale samples show viscoelastic behaviour and relatively weak mechanical parameters (low Young's modulus, cohesive strengths and friction coefficients, high possion's ratio) under triaxial compression conditions. With the increasing of confining pressure, shales gradually transform from brittleness to ductileness. A comparison of static mechanical parameters between our samples and North America indicates that black siliceous shales of Longmaxi formation have moderate Young's modulus and Poisson's ratio.