bluuebunny/crossref_metadata_2025_split huggingface dataset:
Workflow for the Estimation of Initial Water Saturation in a Low Permeability Carbonate Reservoir in a Marginal Field and its Impact on Field Development Planning, Case Study from Abu Dhabi, UAE
Authors: Khan Muhammad Faisal , Maskari Shaymaa Ali , Voleti Deepak Kumar , Kundu Ashish , Al-Rawahi Ali Salem 
Published: November 2017

Abstract
It is always a major challenge to estimate accurate initial water saturation in low relief/marginal fields. Several methods for calculating water saturation have been proposed in the industry, however each method has its limitation and relying on any single method will have direct impact on field development planning in early stages of the field. The objective of this paper is to present workflow that integrates multiple methods and help in defining uncertainties associated within each method to finalize water saturation model.
Different methods such as, resistivity, dean stark, sigma, NMR and capillary pressure (Pc) approach were used to estimate accurate initial water saturation. The Sw resistivity method was computed using Archie's parameters such as; log derived deep resistivity and electrical properties from the SCAL data eg: cementation factor (m) and saturation exponent (n). The sensitivity analysis was performed to find which parameter contributes more to Sw uncertainty. Sigma method was used to compute Sw independent of resistivity. The main sigma inputs are sigma matrix, sigma hydrocarbon, sigma water and porosity. NMR was used to compute Swirr using total NMR porosity and free fluid porosity, it helps to bracket the minimum water saturation of the field. The capillary pressure approach was used for saturation height function (SHF) by grouping the Pc data into Petrophysical Rock Types (PRT). The Skelt Harrison function was used to fit Pc shapes observed in different rock types to develop SHF.
The Sw sensitivity analysis indicates that water resistivity (Rw) and saturation exponent (n) have a minimal contribution to Sw uncertainty compared to the cementation factor (m), therefore variable m approach was used to narrow down uncertainty. Three different models for Sw_log were derived (minimum, base and maximum) as strong relationship were found between Petrophysical Groups (PGs) and m values. In order to get an accurate Sw_sigma computation, Sigma matrix and porosity indicate very little impact on Sw_sigma, whereas Sigma water found to be the highly uncertain parameter, due to the mixing of mud filtrate (Faisal. et. Al,. 2016) since the reservoir is in transition zone and the measurement's volume of investigation was shallow. Dean stark approach was also not reliable due to the invasion effects found. For the SHF, the Pc data was grouped into five PGs in which the best rock is characterized with a smaller (Pd), better pore size, and lower Swi. The workflow explains different ways and aspects of Swi estimation and gives interpreter the range of Swi uncertainty to do dynamic parameter sensitivity for optimum field development planning.
Successful Field Trial of a Shear-Resistant, High-Injectivity, Reservoir-Triggered Polymer
Authors: Chappell David , Stapley Jon , Rashid Bilal , Towns Martin , Andrews William J. , Kiani Mojtaba , Salehi Mehdi 
Published: November 2017

Abstract
This paper describes the successful execution of an inter-well field trial to test a novel reservoir-triggered polymer technology (the Polymer) which has been proven to mitigate two of the major operational and economic challenges facing polymer injection for enhanced oil recovery (EOR), particularly in the offshore environment. The challenges of shear degradation and reduced injectivity are overcome by delaying the development of viscosity until the Polymer is in the reservoir.
The field trial was conducted in an onshore sandstone oil field in Texas. The 1,000 ppm Polymer solution was injected at rates of 500 to 900 bbl/d into a 10-ft interval of low water permeability (50-100 mD) under matrix conditions. To demonstrate development of its expected viscosity in the reservoir, the growing Polymer bank was sampled from an existing producer. Pressure Transient Analysis (PTA) was used to confirm the deep-reservoir behaviour of the Polymer.
Field data demonstrates that the Polymer behaves as intended. The viscosity of the produced Polymer samples corresponds to the target viscosity as determined from surface activation of the Polymer at the same concentration. This confirms the shear-stability of the Polymer in its un-triggered form. In addition, the injection pressures were no greater than expected and significantly lower than the expected injection pressures, under matrix conditions, for an equivalent partially-hydrolysed polyacrylamide (HPAM). PTA indicates a bank of fluid of increased viscosity some distance from the injector, as designed.
The Application of Geological Concepts for Various Types of High-Permeability Streaks to the Full-Field Simulation Model History Matching of Carbonate Reservoir, Offshore Abu Dhabi
Authors: Shibayama Akira , Hamami Mohamed Tariq , Yamada Tatsuya , Kohda Atsuro , Farhan Zahra Abdulla , Bellah Sameer , Shibasaki Toshiaki , Jasmi Sami Al 
Published: November 2017

Abstract
This paper presents a case study of full-field simulation model history matching by applying geological concepts for various types of high-permeability (high-K) streaks.
An Upper Jurassic reservoir in "Field-A" is domal shape structure and reservoir fluid is under saturated with bubble point. Field-A has been producing oil from the reservoir for 30 years with total 20 oil producers, by evolved through the secondary recovery stage, such as crestal auto gas injection (non-miscible gas), then shifted to crestal water injection to maintain reservoir pressure. The fluid monitoring results and water-cut/GOR evolution trend indicate complexity and heterogeneity of the reservoir.
Two type of high-permeability streaks associated with stromatoporoid lithofacies in the upper part and fault related fractured dolomite in the lower part of reservoir were identified through the reservoir characterization studies. The zones having the high-permeability streaks show higher well-test KH compared to the core plug based matrix KH. Model KH of the zones including high-permeability streaks were conditioned by maps of the excess KH with the following concepts:
Stromatoporoid lithofacies:
Excess KH map was generated based on the relationship between well-test KH and stromatoporoid lithofacies thickness.
Fault related fractured dolomite:
Core observation indicates high density of open fractures is detected in dolomite of specific layers in the lower part of reservoir. Excess KH map was generated based on the relationship between excess KH and fracture density distribution estimated by 3D seismic dip attribute (fault location dependent)
Through model history matching, stromatoporoid thickness distribution in-between well control points were adjusted to modify excess KH map as one of the major uncertain parameter in the global level matching phase, considering its significant impact on pressure communication between crestal gas/water injectors and flank oil producers at overall area and history period. When it comes to local area (well-by-well level) matching phase, independent fine tuning process of excess KH maps derived from two different high-permeability streaks allowed us to achieve good matching quality for pressure, water-cut and GOR, especially for multi-lateral completion wells where injection water/gas breakthrough was occurred at different timing at each horizontal branch. The permeability modification along with the geological concepts of various high-permeability streaks contributed to achieve reasonable quality of history matching without extreme and un-realistic adjustment of the permeability model.
Waterflooding in Giant Carbonate Reservoir; Successes and Challenges
Authors: Mahmood S. , Salazar P. , Zhao X. , Pointing M. , Sayed A. 
Published: November 2017

Abstract

Objectives/Scope
The Mishrif reservoir in the Rumaila field is one of the largest carbonate oil reservoir in the world. The reservoir exhibits heterogeneity from good grainstones to poor lagoonal mudstones, with the presence of thin high permeability layers containing vuggy porosity. Since 1973, the Mishrif Reservoir went through several production phases which indicated lack of pressure support. Line-drive waterflooding presented risks of bypassed oil, low sweep efficiency and high residual saturations due to reservoir heterogeneity leading to low recovery.

Methods, Procedures, Process
The reservoir development has been modified from a line-drive towards a progressive pattern-flood to mitigate key uncertainties and risks for improved oil recovery. After a field trial, large scale water injection in the North of the reservoir began in 2014. This is achieved by utilizing existing infrastructure, converting some existing Producers to Injectors and carefully reactivating existing well-stock following the water injection response. A drilling campaign is planned to complete the inverted 9 Spot pattern, combined with the gradual upgrading of existing facilities. This will be followed by a 5-Spot pattern depending upon drainage and sweep performance.

Results, Observations, Conclusions
The results to-date are promising with a successful ramp up of production from ~150mbd to +400mbd from +200 active wells while successfully maintaining reservoir pressure above saturation pressure with current water injection of over 400mbd. In order to optimise the full field development and effectively mitigate by-passed oil and poor sweep efficiency risks, the sweep patterns must be properly understood across the various reservoir layers and areas. As the production and injection ramp-up continues, water injection priority is being continuously optimized along with reservoir surveillance with specific focus on monitoring reservoir pressure and water-cut trends in the producers to understand sweep and drainage across this giant reservoir. This will need to be complemented with the well conformance through a well thought out completion strategy and effective water shut-offs. The development plan is estimated to achieve an aerial sweep efficiency of ~75% in the most developed water flood patterns by 2035.

Novel/Additive Information
In addition to the production ramp-up, progressing pattern-flood and waterflood management, future development options are being evaluated. This involves fully utilizing learnings from the reservoir performance to-date and further developing deeper understanding of this world-class carbonate reservoir using new technology to further enhance production and recovery in more challenging reservoir quality areas.
The ALBION Project: An Observatory in the Heart of a Carbonate Reservoir
Authors: Massonnat Gérard J. , Rolando Jean-Paul , Danquigny Charles 
Published: November 2017

Abstract
The ALBION project applies a new and disruptive methodology of reservoir characterisation to the carbonate Urgonian Formation (South-East France) considered as the very best analogue of Mid Cretaceous reservoirs from Middle East. Thanks to numerous field sections and outcrops descriptions, to tens of wells drilled in the reservoir, to kilometres of cores, to monitoring of groundwater dynamics such as decades of hydraulic observations at pretty much the only natural outlet of a major groundwater reservoir (Fontaine-de-Vaucluse spring) and to a unique underground laboratory (LSBB, about four kilometers in the heart of the reservoir), a multi-scale model is being built for reservoir purpose. Different observation sites with wells whose spacing ranges from 2 to 20 meters contribute to the assessment of together the matrix, the fractures and the karst flow behaviours. Through the building of an observatory in the heart of a reservoir, the ALBION project is delivering advanced concepts and methodologies to apply to industrial projects in Middle East carbonate fields.
Selection and Deployment of Downhole Self-Equalizing Sub-Surface Safety Valves over Non-Equalizing Sub-Surface Safety Valves in Deepwater Wells
Authors: Singh Dheeraj 
Published: November 2017

Abstract
An operator in the deep-water block planned to drill additional wells targeted into the gas cap of depleted reservoirs via sidetrack operations. Historically in this field, as part of the completion systems design, the use of non-equalizing safety valves were selected for the applications largely due to concerns associated with integrity of the well completions over the life of the well.
The surface controlled subsurface safety valves (SCSSV) were set at depths in the wellbore below the hydrate stability region, to mitigate concerns of hydrates around the safety valve, as well as slam closure specifications required for high velocity flow rates of hydrocarbon fluids (oil/gas) through the safety valve. Since the SCSSVs were non-equalizing, in order to open the valve, hydraulic pressure typically generated by a liquid column, is applied to equalize across the valve’s closure mechanism prior to opening with the control line fluid.
During completions and interventions operations, the liquid column to equalize the safety valve at the subsea safety valve depths of 1000 meters from the rig rotary table and use of 9 5/8" 53.5 ppf landing strings, could be upwards of 300 bbl of liquid. This presents a problem when the valve is equalized in a gas well environment because the liquid is expected to drop into the wellbore once the safety valve is equalized and fully opened. In the case of depleted gas reservoirs, there is an increased risk against the gas reservoir naturally flowing and cleaning up this liquid volume from the well, and is further compounded with high flow line pressures, resulting in an inability to produce the well. After careful consideration, the above risks were identified, and a possible solution of using a self-equalizing SCSSV to mitigate the need to use a liquid column to equalize the system and enhance the natural ability of the well to flow was advised.
Selection of Downhole Safety Valves in Deepwater applications is most significant aspect of well completion design; especially in depleted reservoirs. An operator should judiciously select from Self-Equalizing and Non-Equalizing Safety Valves available in the market.
Frac Modeling: Integrating Proppant Transport with Geomechanical Properties for Long-Term Results in Liquids-Rich Plays
Authors: Yusuf Ahmed , Bilgesu Ilkin 
Published: November 2017

Abstract
Several techniques for hydraulically fracturing design were conducted in the liquid-rich Eagle Ford developments. This study shows that different results were observed due to the variation of geomechanical stresses of the rock across a play and reservoir properties. An optimum treatment for a liquids-rich objective is much different than that for a gas shale primarily due to the multiphase flow and higher viscosities encountered.
This paper presents a treatment workflow that has been used with liquids-rich window of the Eagle Ford Shale. Review and integration of data from multiple sets across the play were used as input to a 3D hydraulic fracture simulator to model key fracture parameters which control production enhancement. These results were then used with production analysis and forecast, well optimization, and economic model to compare which treatment designs yield the best placement of proppant to deliver both high initial production and long term ultimate recoveries.
A key focus for this workflow was to maximize proppant transport to achieve a continuous - optimum conductive - fracture half length. Often, due to the complexity of unconventional deposition, it is difficult to maintain complete connectivity of a proppant pack back to the wellbore. As a result, much of the potential of the fracture network is lost. Understanding the interaction of a hydraulic fracture and the rock fabric helps with the design of this behavior to achieve best results. These results can then be used for determining optimum well spacing to effectively develop a selected reservoir acreage.
Currently, there are numerous wells and over two years of production history in much of the Eagle Ford. Comparison of these production results demonstrate the importance of employing a diligent workflow to integrate the sciences so that a proper understanding and application of hydraulic fracturing modeling can be achieved.
Guideline for Development of CO2 Capture, Transport and EOR Integrated System for UAE
Authors: Singh Prachi , Geuzebroek Frank 
Published: November 2017

Abstract
Based on ADNOC 2030 vision and several initiatives taken in UAE to reduce carbon emission, it is essential to look into the suitiable options for CO2 capture and its utilization with a focus on EOR application in UAE. Hence, a high-level roadmap for carbon capture and utilization (CCU) project is proposed in this work. This gives guidelines and directions for activities required to develop successful future CCU projects in UAE. It is a crucial first step to evaluate the potential CO2 emission sources suitable for CO2 capture technology i.e. single point sources in UAE. Power generation followed by cement industry are the largest CO2 emission sectors in terms of CO2 volumes followed by oil and gas industry. This work indicates that source to sink matching is essential at this stage to develop a suitable CCU infrastructure. Moreover, further investments in research and development are required to develop low-cost CO2 capture technologies suitable for low CO2 concentration emission sources such as natural gas fired power generation.
Impact of Near-Surface Heterogeneity on Seismic Reservoir Monitoring Simulated Using the Real Field Data in Abu Dhabi
Authors: Nakatsukasa M. , Nakamura Y. , Kato A. , Hagiwara H. , Grandi A. , Elila A. K. 
Published: November 2017

Abstract
Time-lapse (4D) seismic in onshore Abu Dhabi is extremely challenging. Velocity changes due to fluid displacement are very small: time-lapse P-wave velocity changes after 3 years of CO2 injection are estimated −2% around injection wells. 4D noises are problematic too. Near surface heterogeneities hereafter investigated represent the most dramatic source of non-repeatable noise.
To investigate the behavior of non-repeatable noises seismic modeling has been performed. Surface and VSP seismic were both generated using a 2D Finite-Difference Time-Domain (FDTD) method. Expected 4D effects were modeled through simulation results before and after injection. P- and S-wave velocity, and density model within the reservoir, overburden, and near surface are derived from reservoir simulation models, cores, well log data, and uphole surveys. Time-lapse perturbations are added to near surface intervals to take into account possible variations.
Surface seismic gathers show predominant elastic scattering, hence near surface non-repeatable noises overwhelm time-lapse (4D) changes. On the other hand, VSP gathers exhibit clearer reservoir reflections and time-lapse. After reverse time migration 4D processing, VSP data indicate the main potential to detect 4D changes. Source and receiver positioning errors are also included, as such errors usually create strong bias. This study confirms that source position repeatability is critical and therefore a permanent seismic monitoring system would be required for successful detection in onshore Abu Dhabi.
Identification of a Cost Competitive Development for a High-Pressure, High-H2S Richest Gas Condensate Carbonate Reservoir in the Sultanate of Oman
Authors: Mourad Ahmed , Calvert Stephen , Djermouni Karima , Hattali Ahmed , Nabhani Abdullah , Noirot Jean-Christophe , Naamani Ali 
Published: November 2017

Abstract
The development of high rich gas condensate carbonate reservoirs remains very challenging for the industry especially when the fluid is near critical conditions Ref (5). In some cases, the presence of high pressure, high H2S and CO2 in these reservoirs adds further to the complexity. In these circumstances, it is very important that detailed field development screening and planning are conducted to identify effective and cost competitive development solutions early in a fields life, preferably before starting commercial production.
A compositional simulation model of the richest gas condensate carbonate reservoir in the south of the Sultanate of Oman has been built to identify and select an optimum development scheme for the field. A representative fluid model based on Equation of State (EOS) is used for predicting the complex and dynamic phase behavior of the reservoir hydrocarbons. The performed simulations confirm that achieving maximum ultimate recovery for both gas and condensate is very challenging in this type of reservoir. The most effective recognized technique for maximizing the condensate recovery is gas recycling for pressure maintenance. A feasibility comparison was performed between no gas injection (depletion production), partial pressure maintenance (10 and 20 years of gas re-injection) and full pressure maintenance (long term gas re-injection). In addition, different sensitivities were considered to come up with an optimum development based on key economic indicators: Net Present Value (NPV); Value Investment Ratio (VIR) and Unit Technical Cost (UTC).
On the basis of the study results, it clearly appears that a gas recycling development is the best option to significantly increase condensate recovery (up to doubling it). However, economical evaluations show that a gas depletion development leads to higher NPV and VIR, mainly due to the early production of gas and the expected high surface facilities Capital Expenditure (CAPEX) associated with gas recycling in this type of high pressure, high souring, and very rich gas condensate carbonate reservoir.
This paper highlights and summarizes the challenges faced during the identification of a cost competitive development in high-pressure, highly sour, very rich gas condensate carbonate reservoirs.