bluuebunny/crossref_metadata_2025_split huggingface dataset:
Utilization of Waste Water Stream for Heavy Oil Recovery
Authors: Shammouh Dalal , Chakraborti Pradip , Farhart James 
Published: December 2016

ABSTRACT

Objective/Scope
The extraction of Heavy Oil (HO) from the soon-to-be developed Lower Fares South Ratqa field requires steam injection to enhance HO recovery. The amount of water required for this facility is quite high, up to 210,000 barrels/day (in excess of 33 million liters per day), and the availability of suitable water is problematic, particularly in a dry country such as Kuwait.
Enhancement of Heavy Oil (HO) recovery can be effected via cyclic steam stimulation and steam flood techniques. However, steam generation is highly dependent on the availability of sufficient quantities of suitable water.
Potential water sources for steam generation include seawater, rivers, lakes or underground bodies of water. The last three are unavailable in sufficient quantities in Kuwait and specifically in North Kuwait.

Methods / Procedures / Process
Seawater was initially considered as a source water option for the Lower Fares Heavy Oil (LFHO) project but further investigation identified another potential water source – a Reverse Osmosis (RO) reject water stream from the Sulaibiya Sewage Treatment Plant (SWWTP) – as a feasible option.
After careful assessment, KOC selected the RO reject water stream from the SWWTP as the optimal solution. This innovative application utilizes a currently discarded resource and eliminates the environmental concerns associated with discharging this resource to the sea.
KOC requires up to 210,000 barrels/day water to feed the Once-Through Steam Generators (OTSG's) to produce 80% quality of steam for injection into the wells. The water treatment technologies available in the market were evaluated to ensure that the RO reject stream could be successfully treated to achieve a suitable water quality for steam generation.

Results, Observations, Conclusion
The LFHO Project will utilize the SWWTP RO reject stream to enhance HO recovery in North Kuwait. The discharge of this stream to the sea is currently considered as an environmental concern. The use of this reject stream was previously not considered possible as no potential usage opportunities were identified.
This paper covers the usage of this RO reject stream as the source water for steam generation for enhanced HO recovery.

Novel/ Additional Information
The use of RO treated water streams in the petroleum industry as make-up water for cooling water towers and cleaning applications is fairly common.
The use of an RO reject water stream for steam generation to enhance HO recovery is a novel application for the petroleum industry.
Novel Benchmark and Analogue Method to Evaluate Heavy Oil Projects
Authors: Jia L. , John A. , Kumar N. , Bialas R. , Lanson T. P. , Jing X. D. 
Published: December 2016

Abstract
This paper presents a benchmarking strategy specific to heavy oil projects using thermal recovery methods. We use the new approach to benchmark heavy oil development projects and identify gaps in performance and suggest measures to close those gaps.
Typical benchmarking studies for development projects compare Reservoir Complexity Index (RCI) against Estimated Ultimate Recovery (EUR) to evaluate the performance of the projects. Shell developed a proprietary top-quartile expected ultimate recovery (TQ EUR) tool to compare fields in primary recovery and water flood. For this study, a new method was developed to calculate the RCI for heavy oil projects. Complexity Attributes and ranking criteria were developed based on key parameters influencing thermal recovery performance. This method was used to evaluate 20 heavy oil projects worldwide. Once RCI is calculated for each project, the reservoir performance and environmental footprint were plotted against RCI to identify the top quartile fields. Oil steam ratio (OSR), EUR, and CO2 intensity were the reservoir and environmental performance metrics considered in this study.
The data collected for the benchmark study included reservoir and fluid properties, reservoir geology, well operation and field development, and field performance metrics. The data sources included Energy Resources Conservation Board (ERCB), Canadian Oil and Gas Companies (Canoils), The Society of Petroleum Engineers (SPE) publications, Shell's Top Quartile Estimated Ultimate Recovery (TQ EUR) Tool and Shell's tool of recovery efficiency prediction in prospect appraisal (SWEEP). A heavy oil development project was benchmarked using the new approach to identify the gaps to top quartile performance and provide guidance and measures to close those gaps.
A novel RCI framework has been developed specifically for Thermal Recovery Projects in Heavy Oil. Project benchmarking data and comparison methodology shown here can be extended to any other producing area in the world.
In-Situ Steam Generation A New Technology Application for Heavy Oil Production
Authors: Al-Nakhli Ayman R. , Sukkar Luai A. , Arukhe James , Mulhem Abddulrahman , Mohannad Abdelaziz , Ayub Mohammad , Arifin Muhamad 
Published: December 2016

Abstract
The recovery of unconventional oil such as heavy oil is receiving great interest as the world oil demand is increasing along with relatively high oil prices. Producing such high viscosity oil is complex and challenging, which usually require thermal techniques. Thermal recovery methods are widely used to recover the heavy oil and bitumen basically by thermally reducing oil viscosity, improving the mobility ratio and enhancing the heavy oil displacement.
In response to the recent effort of leveraging heavy oil and tar plays in Saudi Arabia, Saudi Aramco has launched a new thermochemical research program to tackle challenges associated with lowering oil viscosity to improve well productivity and the overall reservoir depletion efficiency.
One of the promising new technologies is enabling in-situ steam generation by chemical reaction (EXO-Clean) to mobilize the low API crude oil or tar reserves. In this paper a new steam flooding methodology will be introduced and compared with existing technologies. Steam will be generated in-situ by chemical reactions, which will have better efficiency and lower cost compared to conventional steam injection methods. Simulation study, lab experiments, and field treatment showed great promises of the technology.
The developed EXO-Clean treatment relates to in-situ steam generation to maximize heat delivery efficiency of steam into the reservoir and to minimize heat losses due to under and/or over burdens and non-producing areas. The treatment consists of injecting exothermic reaction-components that react downhole and generate in-situ steam and nitrogen gas. The generated in-situ steam and gas can be applied to recover deep heavy oil, and tight oil reservoirs, which cannot be recovered with traditional steam injection methods.
Diluent Injection Optimization for a Heavy Oil Field
Authors: Hoffmann A. , Astutik W. , Rasmussen Flemming , Whitson C. H. 
Published: December 2016

Abstract
Past studies have shown that use of diluent injection with ESPs can be an efficient artificial lift method for heavy oil fields. It consists of injecting a light hydrocarbon liquid to reduce the oil density and viscosity. This paper describes an integrated modeling solution designed to maximize the reservoir oil production while minimizing the diluent requirement and keeping the crude oil quality within technical and marketing specifications. The field studied is an offshore heavy oil asset. It consists of two reservoirs with API gravities of 14 and 12, and oil viscosities at reservoir conditions of 70 cp and 500 cp. The field includes some 60 production wells.
Diluent can be injected (1) in each individual well at the ESP and (2) in the surface processing facility prior to the second stage separator. Operating constraints include (1) minimum wellhead pressure, (2) diluent availability, (3) final crude quality specifications, (4) maximum field oil and liquid production rate. The difficulty of the production optimization problem lies in the nonlinearity of the well production curves and viscosity model. In this paper, we develop a Mixed Integer Linear Programming (MILP) formulation by piecewise linearizing the nonlinear behaviors. For each well at each time step, we adjust the black-oil rates from a reservoir simulator to create piecewise linear well performance curves giving the reservoir oil production as a function of diluent injected at the ESP.
The proposed integrated solution is used for the entire production life of the field, which is still in the development phase. The solution is coupled with a reservoir simulator (1) to determine optimal diluent requirements over time, (2) forecast field production of reservoir oil, diluent, water and gas, and (3) foresee eventual bottlenecks in the infrastructure design (e.g. limiting constraints). The proposed solution can easily be used as a Real Time Production Optimization (RTPO) tool to find the optimal operating point based on the latest measurements (or real-time data). The optimal solution ensures the highest field reservoir oil production while meeting all constraints and keeping the diluent consumption at a minimum. The increase of the field oil production rate due to optimal diluent allocation ranges from 2 to 10 %. Cumulative reservoir oil production increases by approximately 3 million std m3.
The uniqueness of the solution comes from the integration of all operating constraints into a single mathematical formulation. The computational time (1s – 10s) of the proposed solution outperforms any classical nonlinear approach. This allows running many sensitivity analyses of the entire integrated asset model.
Perforating Strategy for Stimulating Viscous Oil Wells for Both Cyclic Steam Stimulation and Steam Flooding Optimizing Using Perforation Laboratory - A Case Study From Kuwait Oil Company
Authors: Aly Hussein M. R. , Zeidan A. A. , Ahmed K. , Al-Mula Y. H. , Al-Khamees W. K. , Haggerty D. , Akhmadikin V. 
Published: December 2016

Abstract
Laboratory perforation tests were conducted shooting into target formation core at downhole-matching conditions in order to select the best perforating system for optimized production in a viscous oil-saturated, unconsolidated sandstone reservoir. Along with determining depth of penetration, the need was to find the optimal casing hole size for cyclic steam stimulation, requiring smaller holes for effective steam distribution, and holes large enough for minimal velocity during the production cycle.
The first step was to process the crude oil-saturated, unconsolidated sandstone cores taken from the target zone to enable their use with minimal disturbance. Once the cores were prepared such that specific field stress and pore pressure could be applied, shaped-charge perforators were shot to determine resultant hole-entry sizes and depths of penetration. Besides investigating casing hole size which regulates the flow-velocity/drawdown-pressure relationship, other insight gained was understanding the difference between solvent versus heat displacement of the viscous crude oil.
The focus of the testing began with the perforation behavior in the stressed, viscous crude oil-saturated sand, then flow of the viscous crude oil through the sand, and finally on how the viscous crude oil-flow behavior was affected by heat to lower viscosity. Results showed that penetration into the stressed formation core was sufficiently deep regardless of the shaped charge size and the main constituent for shaped charge selection was the diameter of the casing entrance hole. Tests using heat to assess its effectiveness on improving crude oil flow through the sand showed to be most effective while minimizing undesired sand movement.
At the time this abstract was written, multiple wells had been recently perforated and are currently under field evaluation and data gathering, to be compared to the laboratory findings. This paper will include discussion on the testing process used and the effect of perforating the viscous crude oil sand. It will also offer insight into the effects of increasing the temperature of the viscous crude oil and selecting a perforating strategy.
Low Cost Wells Manufacturing for Heavy Oil plays
Authors: Slagmulder Yves , Brown Jeanna 
Published: December 2016

Abstract
Vertical Steam Flood Heavy Oil developments, such as Shell's Carmon Creek project, require a large number of wells. This high well count leads to the wells contributing a large part of the project cost and a large physical footprint.
In the Carmon Creek project, the challenge for Shell was to safely drill and complete thousands of wells at the lowest possible cost while minimizing the footprint. The approach taken was that of a ‘Wells Manufacturing System’, using new technology, bespoke equipment and novel ways of working.
The well construction operations were broken down in repeatable steps. This enabled fast learning and it provided the basis to engineer out ‘flat-time’ activities by designing fit-for-purpose equipment, such as BOP systems, wellheads and drilling rigs. Partnerships in low cost manufacturing locations were formed to build this equipment.
A multi-disciplinary team designed wellpads, not only making them as small as possible, but also to enable the implementation of an assembly line philosophy. Three-dimensional well planning was crucial to establish the optimal well spacing at reservoir level.
Drilling performance in similar developments was benchmarked extensively to be able to set challenging targets and to be able to measure performance.
Given the application of the wells manufacturing system, using the same well design for both injector and producer wells was deemed most cost effective, since the key to the success of the manufacturing philosophy is repetition. This saves time and optimizes the supply chain.
The resulting wellpad design has an unprecedented well count per pad of up to 49 wells, positioned in a single line. The well spacing was driven by how close beam pumps can physically be placed.
The fit-for-purpose rigs have substructures that cover three wells simultaneously and function in essence as self-walking assembly halls, furnished with a super-single drilling mast. The rigs are equipped with double BOP's that can leapfrog. Work on three wells is performed simultaneously and activities such as BOP testing and waiting-on-cement are taken off the critical path.
The rigs were built and operated by a Shell Joint Venture, blurring the boundaries between the traditional roles of operator, drilling contractor and Service Company, based on three principles: Build a Long-term relationship that allows Continuous Performance ImprovementTechnology that results in fit-for-purpose (FFP) equipmentVery attractive pricing that is not coupled to North American market volatility
Drilling commenced in 2014 and performance has been excellent, particularly with learning by repetition exceeding expectations. The Project itself was cancelled due to political and economic reasons, but drilling on two pads was completed prior to the project halt. In total, 92 wells were drilled, with 65 wells achieving ‘Best in Class’ time and cost performance, and 77 Top Quartile wells. Well times and costs as a result decreased by up to 50%.
Production Optimization through Voidage Replacement using Triggers for Production Rate
Authors: Temizel Cenk , Kirmaci Harun , Wijaya Zein , Balaji Karthik , Suhag Anuj , Ranjith Rahul , Tran Minh , Al-Otaibi Basel , Al-Kouh Ahmad , Zhu Ying , Yegin Cengiz , Aminzadeh Fred 
Published: December 2016

Abstract
Voidage replacement is a key element in displacement processes, not only for keeping the reservoir pressure at its initial level but also in mitigating surface subsidence in certain fields. Despite its simple definition, it is a complicated process in reservoir management because of uncertainities involved and lack of all required measurements due to economical or technical restrictions. Thus, every single decision parameter and their relative significance in voidage replacement process is important for robust reservoir management.
In general, voidage replacement is achieved where injection is based on production. This study investigates the case of triggers where the production rate at the bottom hole conditions is predicated on the bottom hole flowing conditions or reservoir gas injection rate. A full-physics commercial reservoir simulator is coupled with robust optimization software, where a miscible flood operation is modeled with a group bottom hole flowing target coupled with voidage replacement gas and water injection targets.
The simulation results of this realistic case is presented in a way to show the relative significance of each operational parameter, which is outlined with tornado charts to serve as a guide in decision making in efficient reservoir management where voidage replacement is a crucial component. It is observed that triggers help to better manage voidage replacement, especially in large reservoirs where reservoir surveillance is a challenge due to number of wells and patterns. The results can be scaled up to different size of reservoirs and patterns with similar recovery processes.
This study scrutinizes the feasibility of a reversal of the typical scenario where injection is based on production. Thus, it serves as a useful and realistic example for efficient reservoir management through optimization of voidage replacement through triggers for production rate.
Estimating Oil/Water Relative Permeability at SAGD Steam Chamber Edge
Authors: Mosavat Nader , Mohsenzadeh Adel , Al-Wahaibi Yahya 
Published: December 2016

Abstract
Fluid flow at the edge of SAGD chamber where most of bitumen drainage occurs is of great importance. In this region, water condensate co-flows with the falling bitumen towards the production well. Since the bitumen viscosity varies at different locations due to temperature gradient across the edge of steam chamber, new correlations are required to consider the influence of fluid viscosity on the relative permeability curves. In this study, the objective is to remedy this deficiency by developing a new set of correlations for relative permeability estimation addressing in particular such effect at SAGD steam chamber edge.
Various datasets from literature were obtained at different temperatures and oil viscosities. The data were used to develop new correlations which are a modification of the well-known Corey's equations for relative permeability estimation. Two mathematical approaches were applied and evaluated to achieve the best correlations: (1) at each temperature, herein substituted by viscosity ratio, relative permeabilities are functions of saturation, and (2) relative permeability is a function of viscosity ratio at a fixed saturation. Furthermore, different mathematical equations were used in the regression procedure in order to optimize the objective function and achieve the most reliable correlations.
Results indicated a combined power and quadratic functionality of relative permeability to the phases’ viscosity. The viscosity ratio was used in the new correlations as a dimensionless parameter which represents fluids’ viscosities at different temperatures. The new correlations were compared against the original Corey's equations for various experimental datasets. Various statistical error formulation were employed: average relative error, average absolute relative error, root mean squared, correlation coefficient, and standard deviation. The accuracy of the new correlations was also graphically compared with Corey's model using cross-plot illustrations. Comparative evaluation of these correlation error analyses revealed that relative permeability estimations have been significantly improved when new correlations were employed which incorporate different temperature profiles and accordingly the viscosity variations. The application of the new correlation could improve the flow prediction in thermal simulators.
Integrated Rock-Typing Workflow in Shallow Unconventional Reservoir in Kuwait
Authors: Saikia Pabitra , Shanat Faisal , Ahmed Khalid , Choudhary Pradeep , Ferdous Hasan , Ahmed Fatma , Fournier Frédérique 
Published: December 2016

Abstract
Heterogeneous lithofacies distribution resulting into a complex rock-type model in shallow unconsolidated reservoir has a direct role on fluid distribution and trapping mechanisms. A systematic evaluation of these rock-types is necessary for proper reservoir characterization and modeling. In reality, the lithofacies leading to rock-types act as the building blocks to construct a realistic static model, which serves in the understanding of the dynamic behavior of the reservoir.
During this study, 202 wells were selected across the field to capture the vertical and lateral heterogeneity of the reservoir, out of which 93 wells have cores. During a first step, a lithofacies prediction model was created from the core sedimentological description, X-Ray Diffraction (XRD), and wireline logs (raw and mineralogical logs) using probabilistic classification schemes. In a second step, petrophysical data like Routine Core Analysis (RCAL), Mercury Injection Capillary Pressure (MICP), were included to build rock-types associated with the different lithofacies. This integration workflow has resulted in a robust lithofacies and rock-type model consisting of nine lithofacies and five rock-types respectively. It was also noticed that silty non-pay and marginal pay reservoir have inadequate MICP data. Subsequently, two wells were selected and MICP data will be collected for improved and more confident modelling in future.
This model assists to predict lithofacies and rock-types in un-cored wells provided a set of relevant logs are available. The integrated workflow ensures that the lithofacies and rock-types determined at the wells are consistent all over the study area.
The identified lithofacies and rock-types will add great value in building a realistic reservoir static model since they are able to explain the fluid distribution pattern and the concept of barriers and baffles in the reservoir. This will also assist in optimized perforation and completion plans for the reservoir. Ultimately, the input data are readily available for future field-intensive reservoir characterization.