bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Improved Reservoir Understanding through the Use of a Unique Platform for Reservoir Management and Simulation: Application to Gas Movement Understanding in a Gain Field
Authors: Bashatah Lafya , Helmy Mohamed , Draoui Elyes , Asakawa Kazuhiro , Graves T. Hunter , Alurkar Kaustubh , Jayanti Shekhar , Giordano Ronald M. , Bhangale Amit , Limaye Nilesh , Raut Bipin 
Published: November 2012

Abstract
Streamline analysis coupled with finite-difference simulation provides a novel effective approach for an integrated reservoir management. The output from the existing compositional reservoir model was processed to generate streamlines from the finite-difference simulation. Reservoir management data, historical well performance data, calculations from streamline bundles, and novel performance diagnostics are integrated to optimize the field management and maximize oil recovery. Simulation and field data are combined to give an integrated understanding of the reservoir leading to smart reservoir management. Powerful streamline analysis is being used to help optimize injection and increase recovery efficiency. Real field data and model data are being analyzed to identify the areas of upswept oil and opportunities to improve the reservoir performance. This new methodology workflow is implemented in a user-friendly and intuitive way, giving more time for analysis and integration then data management.
Impact and Lessons of Using High Permeability Streaks in History Matching a Giant Offshore Middle East Carbonate Reservoir
Authors: Brantferger K. M. , Kompanik G. S. , Al-Jenaibi H. M. , Dodge W. S. , Patel H. 
Published: November 2012

Abstract
A new generation geologic model for a giant Middle East carbonate reservoir was constructed and history matched with the objectives of creating a model suitable for full field prediction and sector level drill well planning. Several key performance drivers were recognized as important factors in the history match; 1) unique carbonate fluid displacement; 2) data validation and horizontal well trajectory issues; and 3) distribution of high permeability streaks. Ultimately a full field history match consisting of more than 1000 well strings and several decades of history was achieved using detailed distribution of the high permeability streaks, while honoring measured core poro-perm relationships, lab-validated displacement curves, and well test data.
This paper discusses the role of the geometry and the vertical distribution of the high-permeability streaks in the history matching of a giant offshore carbonate reservoir. Specifically, the modeling of the high-permeability streaks – which consist of thin rudist and algal rudstone, floatstone, and peloidal grainstone, with abundant, well-connected inter-particle porosity - became possible after extensive revamping of the reservoir rock type model, updating well descriptions, and a detailed zonal mapping of the high permeability streaks and dolomitic zones. The areal and vertical model resolution was doubled over the previous models to accommodate the internal sub-layering of the upper four reservoir zones in order to capture the thin (~1.4 ft) high-permeability streaks.
During the history match, local modifications of the high-permeability streaks were the integral part of the feedback loop between the simulation engineers and geoscientists that kept the common-scale simulation model and geologic model synchronized. The final history match was validated by extensive analysis of the models’ vertical conformance as compared to production logs. This approach made it possible to construct a more heterogeneous model than previous models; while honoring both field KH and matrix poro-permeability without local permeability multipliers. The combination of these features provides a higher confidence model of long term well injectivity/productivity.
Water Saturation Modeling in Khafji Carbonate Reservoir
Authors: Al-Otaibi Mohammad H. , Khamatdinov Rafael , Al-Khaldi Nasser , Abdelrahim Rabei , Bouaouaja Mohamed 
Published: November 2012

Abstract
Within an oil reservoir the water saturation height functions can vary strongly, especially for carbonate rocks. These variations can be significant and difficult to estimate. The amount of hydrocarbons in place, the prediction of recoverable oil, the recovery process and the future plans of developing such reservoirs depend on many factors, one of which is the accurate modeling of water saturation.
The Khafji carbonate reservoir is a heterogeneous reservoir with two different types of oil: light oil in the top of the reservoir and heavy oil in the bottom of the reservoir. The challenge of water saturation modeling is primarily in the heavy oil zone, where conventional height function techniques produces poor match against measured water saturation logs. Alternative methods were utilized in order to obtain good match in both light oil and heavy oil columns.
A workflow has been created in order to overcome these challenges. Laboratory derived capillary pressure curves were used to establish water saturation height relationships as a function of rock type (RT). Additionally, a Flow Zone Indicators (FZI) analysis was used as a basis for rock typing. Then a J-function derived from capillary pressure data for each rock type or hydraulic flow unit (HFU) was used to generate saturation height function for each RT. The generated saturation undergone via several iterations to match the large span of openhole electric water saturation logs above the free-water level (FWL).
The saturation profile generated by this workflow shows a good match to the measured Sw electric logs, and the calculated fluid volumes are in agreement with company's approved reserves estimation.
Best Practices for Drilling an Open Hole Multilateral Well in a Structurally Complex, Fractured Carbonate Reservoir in Kuwait
Authors: Dutta Bikramjit , Al-Azmi Bader M. , Dutta Abhijit , Fernandes Warren , Zaki Mohammed 
Published: November 2012

Abstract
This paper discusses the critical requirements for successful well planning, landing, geosteering and completion of an open hole multilateral well, with lateral sections of 2,500 ft and 2,200 ft, drilled in a complex carbonate reservoir in Kuwait.
The structure is dominated by four sets of normal faults trending EW, NS, NW – SE and NE – WS. The reservoir is divided into 10 layers, with reservoir quality generally decreasing from top to bottom. The upper layers exhibit good porosity, vugs and molds while the lower layers are mainly mud-dominated with thin, interbedded brittle layers. As there is no significant water-drive mechanism, the development strategy was to maximize production by connecting the natural fracture network through extensive acid stimulation.
The objective was to isolate problematic formations by landing the well below them, while maximizing reservoir contact in the upper layers. This meant intentionally crossing a major NS-trending extensional fault to maximize fracture intersection and therefore maximize the production potential. Well planning and drilling a high quality wellbore to landing point were identified as critical as the four wells drilled previously had resulted in fishing and side tracking in the intermediate section. Optimizing drilling fluid parameters and drilling practices from the lessons learned, and correct selection of rotary steerable system (RSS) and logging-whiledrilling (LWD) tools that led to a successful landing are discussed, as are real-time wellbore placement to maximize production potential using RSS and LWD tools, following best drilling practices and seismic model integration through multi-faulted environment are also discussed. LWD measurements and their integration into the geosteering model, benefits of a high-resolution resistivity image in aiding the identification of fractured zones for stimulation optimization, hole preparation for completion and success and of massive acid stimulation of the open hole laterals using coiled tubing are also discussed.
An Innovative Approach to 3D Fracture Modeling
Authors: Al-Azri Saud , Al-Raisi Muatasam , Bushara Mohamed N. 
Published: November 2012

Abstract
The production of oil and gas from naturally fractured reservoirs requires a thorough understanding of fracture network connectivity. Predicting fracture continuity & connectivity between wells -considering the immense control of multiple parameters on natural fracture behavior at reservoir conditions-remains to be a daunting challenge. A novel approach has been developed to provide a Continuous Fracture Network (CFN) model that honors the temporal and spacial changes of drivers that influence fracture distribution. This technology has been tested and successfully implemented in different carbonate and clastic reservoirs in the region. Complex reservoirs such as Permo-Carboniferous Alkhlata formation, Cambrian Amin formation, and Cretaceous Natih /Shuaiba reservoirs in Sultanate of Oman are examples of successful fracture modelling studies. These case studies are used to demonstrate various steps of continuous fracture characterization in this paper.
Well data, geological properties and high resolution attributes derived from seismic are integrated to build a 3D fracture model. The Fracture Indicators (FI) from borehole images (BHI) interpretation are correlated and ranked with fracture drivers to generate multiple CFN models on a 3D geocellular grid. A fuzzy neural network is used to evaluate the hierarchical effect of each driver on the fractures.
The training and testing of the neural network are accomplished using existing well data. Once the neural network finds the relationship between the drivers and the fracture intensity, it can be used to predict this fracture intensity in every cell of the field since all the drivers are known and available in the entire 3D grid. The model is subsequently validated by drilling data, blind wells and dynamic data. Effective permeability distribution is computed through dynamic calibration of potential well test data with the CFN models. Both fracture and effective permeability models are used to improve history matching, production optimization as well as picking new wells.
Reliable Steady-State Relative Permeability Measurement for Carbonate Rocks from a Middle Eastern Offshore Reservoir with an In-Situ Saturation Monitoring by X-Ray Ct Scanner
Authors: Watanabe Kazuki , Tsuchiya Yoshihiro , Takahashi Satoru , Okabe Hiroshi , Mitsuishi Hiroshi , Al-Shehhi Hamad Rashed , Al-Hammadi Hamdan Mohamed 
Published: November 2012

Abstract
The results of special core analyses using carbonate rocks from a Middle Eastern offshore reservoir are presented based on laboratory and simulation studies. The study aims to obtain reliable relative permeability in an oil-water system under steady-state conditions, and confirm the resulting relative permeability through a simulation study by comparing water saturation distributions along the core at various injection ratios of water to oil. The difficulties in steady-state relative permeability measurements are to determine water saturations and steady-state conditions as only the effluents are measured. To obtain accurate water saturations, we adopted an X-ray CT (Computed Tomography) scanner that allows us to precisely measure porosity and fluid saturation distributions inside cores under reservoir conditions, especially for reservoir wettability. In addition, not only the ratios of water to oil in effluents but also water saturation distributions derived from CT measurements inside the core were used as a measure of steady-state conditions.
Core flood experiments were conducted with periodic measurements at various injection ratios of water to oil. As a result, we obtained eleven relative permeability points with respect to water saturation calculated from CT numbers.
Next, a simulation study was conducted to confirm the relative permeability curves using a core model where CT derived porosity and absolute permeability were assigned based on the core flooding experiments. Results of the core flood simulations with the resulting relative permeability curves show that the simulated water saturation distributions are in excellent agreement with those of the core flood experiments, especially low injection ratios of water to oil. Through laboratory and simulation work, it is confirmed that reliable relative permeability measurements were made by carefully determining water saturations and steady-state conditions with simultaneously measuring the effluents from the core and monitoring the inside core by X-ray CT scanner.
Hysweet® Technology: A Major Progress in Sour Gas Processing
Authors: Zhao Jing , Weiss Claire , Cadours Renaud , Shah Virenkumar 
Published: November 2012

Abstract
Removing mercaptans from sour natural gas is becoming an important issue with the global trend towards more stringent specifications for commercial gases. Amines have been extensively used on account of their ability to meet severe H2S and CO2 specifications and very high acid gas selectivity over hydrocarbons. Amines however present very limited mercaptans removal capabilities, an additional treatment step is generally required to achieve a stringent specification of total sulfur specification in the sales gas or upstream liquefaction plant.
Total, taking advantage of its extensive know-how and experiences in acid gas removal, has developed the HySWEET® processes, for simultaneous absorption of acid gases and mercaptans. This technology relies on a new hybrid solvent formulation allowing limited coabsorption of hydrocarbons and improved energy efficiency. The HySWEET® process has been in operation since 2008, and the entire gas production of the Lacq plant, France is now treated with this new hybrid solvent. The industrial feedback has confirmed not only higher mercaptan removal, but also lower energy consumption when compared to the AdvAmine™ HiLoadDEA process which has allowed for Lacq gas treatment during most of the lifetime of the field.
The development of the HySWEET®DEA process is now completed and ready for commercialization. An optimized design can now be proposed for any application case targeting total CO2 and H2S removal along with a stringent total sulfur specification. Thousands of laboratory measurements (i.e. thermodynamics, kinetics, physical properties) have been used to develop a rigorous simulation tool which relies on rate-based transfer models validated against extensive pilot and operational test-runs.
The HySWEET®MDEA process is under development, for the selective elimination of sulfur compounds over CO2. Improved mercaptan removal and high energy efficiency have been demonstrated during pilot tests. These pilot test results will be later used to validate the prediction of the simulation tool currently under development.
This paper provides a review of the HySWEET® technology: an update on the HySWEET®DEA process and the latest R&D developments of HySWEET®MDEA.
Microbial Enhnaced Oil Recovery by Bacillus subtilis Strains under Simulated Reservoir Conditions
Authors: Gudiña E. J. , Rodrigues L. R. , Teixeira J. A. , Pereira J. F. , Coutinho J. A. , Soares L. P. , Ribeiro M. T. 
Published: November 2012

Abstract
Microbial Enhanced Oil Recovery (MEOR) is a tertiary oil recovery process in which microorganisms and their metabolites are used to retrieve unrecoverable oil from mature reservoirs. Stimulation of microorganisms that produce biosurfactants and degrade heavy oil fractions in situ reduces the capillary forces that retain the oil into the reservoir and decreases oil viscosity, thus promoting its flow. As a result, oil production can be increased. In previous work, Bacillus subtilis strains that are useful for application in MEOR were isolated from crude oil samples. Those isolates were able to grow and produce extracellular biosurfactants at 40°C under anaerobic conditions in mineral medium supplemented with hydrocarbons. In addition, some isolates degraded the long-chain n-alkanes of paraffinic mixtures. Mobilization of residual oil by those isolates was evaluated using sand-pack columns at 40°C. Additional oil recoveries obtained with the different isolates using paraffin ranged from 16 to 31%. The recovered paraffin showed a decrease in the percentage of large alkyl chains and its viscosity was reduced. In the present work, the degradation of long-chain n-alkanes and the mobilization of residual oil by the same isolates were studied using heavy oil. The results obtained confirmed that the isolates were able of degrading the long chain n-alkanes of crude oil, and also additional oil recoveries between 8 and 10% were obtained. Furthermore, for a better simulation of the oil reservoir conditions, a core flooding equipment that can work at the oil reservoir pressure was designed and will be used to confirm the applicability of selected isolates to increase oil recovery. The sampled reservoir consists of sands with an average porosity of 25% and a permeability of 50mD. The oil is paraffinic, with low viscosity, high pour point and a gravity of 25° API, with very low solution gas. The reservoir pressure and temperature are respectively 398-440psi and 40°C.
Water Saturation (Sw) from Logging-While-Drilling Resistivity, Capture Sigma and Core Analysis for ROS Determination in a Giant Middle East Carbonate Reservoir
Authors: Serag El Din Samy , Cao Minh Chanh , Murray Doug , Brahmakulam Jacob 
Published: November 2012

Abstract
Water saturation (Sw) estimates are of prime importance for reserves estimation, reservoir development, and reservoir management. Traditionally, Sw has been derived from the Archie equation with formation resistivity or thermal neutron capture cross-section (Sigma, Σ in stand-alone mode. Either the resistivity or Σ approach requires good knowledge of formation water salinity which can be difficult, particularly in instances of unknown and/or mixed salinities. When resistivity and Σ logs are unaffected by fluid invasion, one can simultaneously compute Sw and salinity from the two measurements as has been done recently using wireline logs acquired in flowing wells.
This paper addresses 2 drawbacks of wireline resistivity-sigma technique: first, it is not always practical to flow the well, and second is the concern about the Σ shallow depth of investigation (DOI). The first drawback might be answered by using LWD to mitigate fluid invasion issues instead of logging a live well. The second drawback is addressed by taking advantage of the newly-developed LWD multiple depths of investigation (MDOI) Σ measurements (shallow Σ, medium Σ, and deep Σ) to determine the presence of invasion. If invasion has occurred, via a new MDOI inversion process analogous to the resistivity step-profile inversion, we estimate both invaded and virgin zone Σ for use in petrophysical applications.
We analyzed LWD MDOI resistivity and sigma logs acquired in an oil-producing reservoir drilled with a low-invasion water-based mud for a remaining Oil Saturation (ROS) study. The coring operation has allowed some invasion to take place, which can clearly be seen from the separation of MDOI sigma curves. The inverted (true) Sigma allows meaningful Sw comparisons between LWD, wireline and core analysis. The errors on estimating water saturation and salinity using shallow Σ, medium Σ, deep Σ, and true Σ are illustrated to highlight the need to correct for invasion before doing quantitative formation analysis with Σ. The results indicate the viability of using LWD measurements to determine ROS in flooded reservoirs with mixed/unknown salinities.
Success & Scope of Infinite Conductivity Fracturing Channels in Cambay Basin of India
Authors: Barasia A. , Ramanathan V. , Christiawan A. , Srivastava A. K , Sharma Vivek , Mishra D. C. , Biswas S. K. 
Published: November 2012

Abstract
Cambay is one of the oldest basins in India producing hydrocarbons since 1960's. It stretches almost 400 kilometers from south of Rajasthan to south of Gujarat in the western part of India and covering 53,000 sq. Km of total area. Cambay basin is contributing almost one-third of India's total onshore oil production. Raising production from Cambay basin is a considerable challenge as major producing fields are all Brownfield's.
Hydraulic Fracturing (HF) is in use since 1980's to stimulate and enhance production from average to poor quality sands of Cambay basin. HF leads to better production results and has helped in enhancing production from this region for a long time. HF success ratio in stimulating these reservoirs dwindled significantly in the last decade due to continuous exploitation and decrease in saturation and reservoir pressures in the area. Enhancing fracture effectiveness & conductivity and reducing pressure drop within fracture was key to overcome this challenge and take the production to the next level.
Maximizing conductivity of proppant pack has its own inherent limitations and this led to the application of channel fracturing for the first time in India in the Cambay basin. Channel fracturing results in decoupling fracture conductivity from proppant pack conductivity and results in infinite fracture conductivity, longer effective fracture half-lengths & reduction in pressure drop in the fracture. Creating stable fracture channels is highly dependent on rock mechanical properties and first hand evaluation of this decides applicability of this technology in a particular field/sand.
This paper discusses the production results of wells treated with open channel fracturing compared to production results of offset wells stimulated by Conventional fracturing technology. Then it sheds light on basic requirement and key factors to be able to decide applicability of this technology in a particular field/sand. In the end applicability of this novel technology in all the major fields of Cambay basin will be discussed with the overall scope of redevelopment of all the major brown-fields of India.
Wellhead Platform Extension Project - Solution for Additional New Well Slot on an Existing Wellhead Platform
Authors: Irawan Chandra , Husen Wahyu Prawira 
Published: November 2012

Abstract
Offshore wellhead platform (OWP) extension is one of Total E&P Indonesie (TEPI) strategic action to slowdown the natural decline of total production by giving possibility to add new well-slot on an existing wellhead platform that its well-slots have been all occupied.
Wellhead platform extension project scope is to extend the existing platform structure in order to accommodate additional three or four new well slots. New well slots will be equipped with Conductor Pipe (CP) Guide above and under water, and also CP Protection Frame. Additional Wellhead Control Panel (WHCP), field instruments, F&G system and electric power supply are also constructed for the new wells. Modification of control system is also required in order to integrate new wells input/ output points and Safety Shutdown System (SSS) to the existing Distributed Control System (DCS) for process control.
As brown field project, OWP project activities are executed in SIMOPS (Simultaneous Operation) condition with production activities. Field Operation team as a host will ensure the project will be done safely within their operation perimeter and with minimum impact to production continuity especially due to unplanned shutdown. Field Operation also responsible to prepare procedure and line-up the system for tie-in between new and existing facilities (i.e. piping and instrument). Generally there will be requirement for platform shutdown period in order to perform final tie-in, commissioning, and final start-up of new facilities.
Offshore wellhead platform extension project include several high risk activities such as: saturation diving, heavy lifting and naked flame jobs within existing live facilities, which become project major challenges and require detailed job risk assessment and good preparation from both Project and Field Operation team. Currently, offshore wellhead platform extension has been successfully implemented on seven TEPI's platforms within three years and with minimum impact to production continuation.