bluuebunny/crossref_metadata_2025_split huggingface dataset:
Feasibility Study of Utilizing Hydraulic Turbines to Recover Excess Power from Water Injection Systems
Authors: AlAjmi Mohammed D. , Mahsoon Ahmed H. , Al-Hajri Nasser M. 
Published: July 2016

Abstract
This paper will outline the results of a field feasibility study to utilize hydraulic turbine applications for power recovery in water injection systems. The working principle of hydraulic turbine includes recovering excessive and unutilized energy in liquid flow systems. This is achieved through converting unexploited injection system pressure to electrical power generated by rotating turbines.
The powered water injection systems are often restricted to meet injection targets as part of the reservoir injection strategy to support oil production. Pressure losses in powered water injection systems take place at surface chokes that regulate injection target rates. Expected pressure losses in an injection flowline was determined through the analysis of frictional and gravitational pressure losses. The injection pump performance curves were also factored in as part of this rigorous evaluation. The feasibility study has been conducted with flexibility in mind to account for future changes in reservoir injection/production strategies.
Field-A candidates were explored and vetted to ascertain the achievability of applying this innovative power recovery concept on existing injection systems. A systematic candidate selection roadmap was established. The objective of this conceptual roadmap is to provide a means for conducting the primary assessment of candidate injection systems in Field-A. Several suitable injection systems were selected after a prudent evaluation of possible power recovery turbines candidates in Field-A. The expected power saving realized from applying hydraulic turbines was quantified in terms of net present value and return on investment. The economic impact from converting this pressure to power a hydraulic turbine was established, bearing in mind: The initial capital investment.Payback period.The projected inflation rate.The equivalent gas sales required to generate this power.
Seawater Fracturing Fluid Development Challenges: A Comparison Between Seawater-Based and Freshwater-Based Fracturing Fluids Using Two Types of Guar Gum Polymers
Authors: Alohaly Maryam , BinGhanim Ahmed , Rahal Raed , Rahim Sabiq 
Published: July 2016

Abstract
During the past several years (i.e., 2006 to 2014), the US transformed the development of shale oil and gas from slow and steady into a shale gas boom by combining two already existing technologies—multistage hydraulic fracturing and horizontal wells. This helped the US once again be energy-independent regarding natural gas supply (Charlez 2015). Inspired by such success, the Kingdom of Saudi Arabia and the Middle East region are meeting the increasing energy demand by following similar steps (Bartko et al. 2012).
Large stage sizes in hydraulic fracturing and horizontal drilling long laterals require large quantities of freshwater. Despite the fact that the Arabian Peninsula lacks freshwater resources, fresh water is still consumed by the oil and gas industry in the region. Conversely, seawater is plentiful and should substitute for freshwater in unconventional resource operations. However, the high salinity of seawater raises many chemical challenges in developing design criteria for fracturing fluids.
To help mediate this problem, this paper studies the chemistry of developing seawater-based fracturing fluids using two types of polymers as gelling agents and compares results to already existing freshwater-based fracturing fluid data under different conditions. Various seawaters from around the world were compared to Arabian Gulf seawater and its various compositions throughout the year. The local seawater's high total dissolved solids (TDS) measurement is 54 000 mg/L and includes sulfate (&gt;4000 mg/L), calcium (&gt;600 mg/L), and magnesium (&gt;1700 mg/L). These are the major ions that cause delayed hydration, alteration of the crosslinking mechanism, and high scale formation, along with barite (BaSO4).
Moreover, the paper presents a better understanding of fluid behavior by studying the effects of sulfate (&gt;4000 mg/L), calcium (&gt;600 mg/L), and magnesium (&gt;1700 mg/L) individually to observe fluid stability at high temperatures in both polymers.
A Novel Approach to Predict Wellbore Stability - Use of Thermogravimeteric Characterization to Quantify Rock-Fluid Interaction
Authors: Patil Umesh , Yadav Prahlad , Agrawal Gaurav 
Published: July 2016

Abstract
This paper reports the laboratory study to check the influence of water content, amount, distribution, and water types, on shale reactivity. Even though it is known that any change in water content affects shale behavior, quantification had not previously been attempted. A new method using thermogravimetry (TGA) is developed to determine the water content and provided the opportunity to quantify water loss severity due to dehydration. For a complete understanding of shale-fluid interaction, a more detailed characterization methodology was necessary. The most popular method used by the industry, X-Ray diffraction (XRD), has limitations with shale samples. The proposed methodology uses TGA and is presented here. It has several advantages when compared to XRD. The composition of the rock can easily be identified and structural changes of the rock can be observed.
Modelling the Coupled Effects of Temperature, Injection Rate and Microbial Kinetic Parameters on Oil Recovery by Microbial Flooding
Authors: Sivasankar P. , Govindarajan Suresh Kumar 
Published: July 2016

Abstract
Before the implementation of microbial enhanced oil recovery (MEOR) technique in reservoirs, the microbes used in the MEOR process must be characterized based on the reservoir conditions that include reservoir temperature and also based on the microbe's kinetic parameters that includes yield of microbes with respect to nutrient (YXN) and yield of biosurfactants with respect to nutrients (YPN) for efficient recovery of crude oil from hydrocarbon reservoirs. In addition to chrecterization of microbes based on the reservoir temperature and on its kinetic parameters, the operational condition such as injection rate has also to be selected suitably for better oil recovery and to make the microbial enhanced oil recovery (MEOR) process an efficient technique. Hence in the present study, sensitivity analysis of reservoir temperature, injection rate and microbial kinetic parametrs on MEOR processes has been carried out to characterize the microbes and to identify the suitable injection rate for the MEOR process. For this purpose, a black oil microbial enhanced oil recovery (MEOR) simulator has been developed by coupling of thermo-hydro-biochemical multispecies reactive transport model with the non-isothermal multiphase fluid flow model that can predict the oil recovery at varied reservoir temperature conditions. The developed mathematical model has been solved numerically by finite volume discretization technique. The identification of suitable conditions of microbe, nutrient and injection rate to maximize the oil recovery has been carried out by investigating the sensitivity of reservoir temperature, injection flow rate and yield of microbes with respect to nutrient (YXN), yield of biosurfactants with respect to nutrients (YPN) on MEOR processes. It is found that the microbes used for MEOR application should have its survivable temperature range within the reservoir temperature for an effective MEOR application. Further, it is observed that for maximizing the oil recovery by microbial flooding process, the adopted injection rate should increases the capillary number to 10-3 within the reservoir which has to be achieved by increasing the mean aqueous phase fluid velocity and also by lowering the Interfacial tension. Finally, it is also found that more of the residual oil is recovered when the utilization of nutrients for biosurfacatnt production is greater or equal to the nutrients utilized for the microbial growth. Hence for an efficient MEOR application, the nutrient selected for the application should yield more biosurfactants than yielding the microbes that are selected for the MEOR application.
A Cost-Effective Method to Maximize the Hydrocarbon Recovery by Optimizing the Vertical Well Placements through the Simulation Opportunity Index
Authors: Saputra Wardana , Ariadji Tutuka , Patzek Tadeusz W. 
Published: July 2016

Abstract
During periods of low oil prices, profitability of field developments drops drastically. To help with this difficulty, we offer a cost-effective method of boosting hydrocarbon recovery by optimizing well locations.
A new software program has been developed to optimize vertical well placements based on the Simulated Opportunity Index (SOI). SOI is an intelligent method to identify zones with high potential for production. The production potential of an oil & gas field area is empirically calculated from basic rock and fluid properties, and from reservoir pressure as its energy capacity. In order to obtain the best results, the original SOI formula (Molina et al., 2009) was extended to both oil and gas fields.
With the new SOI software, it is possible to rank the best layers in each areal location, resulting in appropriate vertical well locations and perforated intervals in multilayer reservoirs. Furthermore, the developed software can account for the effects of existing wells and sealing faults to accommodate infill programs in brown fields and compartmentalized reservoirs.
This paper describes how the software helps in obtaining optimal solutions with better accuracy than previous studies resulting in the highest recovery for three different case studies in an oil and gas field located in offshore Indonesia. The sensitivity analysis that was performed shows a strong relationship between SOI value and recovery factor. It validates that the higher SOI values selected by the software give higher recovery factors.
The developed software could boost field development projects even in the period of low oil prices. On one hand, the proposed method could save money by minimizing the required number of wells. On the other hand, it could maximize profit by maximizing recovery.
Oil Well Flow Rates and Components Fraction Prediction Using Nonparametric Variable Similarity Based Modeling
Authors: Abado S. , Hu X. , Shah V. 
Published: July 2016

Abstract
The Variable Similarity Based Modeling and Virtual Signal Generation algorithms are applied to continuously predict (infer) the values of flow rates and component fractions in between periodic oil well tests. This method uses the time-varying signals collected during irregular well tests to train a nonparametric regression model which represents the current operating state of the well. Additionally, this approach also provides the benefit of early warning on potential well performance degradation or other anomalies. The proposed approach was shown of being able to predict the oil, gas and water flow with relatively small errors (~3%, ~3% and ~10%, respectively).
New Non-Explosive Setting Tool
Authors: Al-Julaih Bassam , Christie Stewart , Duncan Neil , Church Paul 
Published: July 2016

Abstract
Historically bridge plugs, packers and gauge hangers were set with explosive charge or hydrostatic setting tools. The logistical and safety issues associated with explosive type setting tools has resulted in more operators moving towards non-explosive setting tools over the last two decades. Hydrostatic setting tools have limited setting force capability related to well conditions.
This paper discusses the design and benefits of a new electro-mechanical setting tool, the New Setting Tool, which aims to significantly reduce operating costs while greatly improving ease of use and reliability.
The New Setting Tool addresses many of the issues associated with commonly used setting tools. The New Setting Tool does not require highly trained personnel or explosives. The tool does not require re-dress after each run and does not require lithium battery packs. Lithium battery packs are commonly used in electro-mechanical setting tools and are classed as dangerous goods. Regulations regarding the shipment of lithium batteries have become more stringent in recent years increasing the time and costs associated with shipment and disposal.
In memory mode, the New Setting Tool utilizes a simple, patent-pending touch screen interface called Cyclops Touch, on the tool body. Touch screen technology is common place in everyday life. A major technical challenge in the design and development of New Setting Tool was to introduce this technology into a downhole tool that is subject to the extremes of temperature and pressure associated with an oil or gas well.
This technically advanced user interface has reduced the requirement for extensive user training. The operator can program the tool and interrogate diagnostic information without the need to disassemble the tool at surface or break any field connections. This is a significant benefit when working in hazardous areas.
The New Setting Tool has an integral auto-reset feature which re-sets the tool for redeployment in less than a minute.
The setting tool comprises of three main sections, the power section, Cyclops section and the hydraulic section. Each section has been designed with specific parameters to ensure the tool is highly reliable and easy to program and run. The non elastomeric seal design allows the tool to be run up to 50 times without re-dress. This improves efficiency and reduces personnel requirement on location.
Estimating the Degree of Inter-Reservoir Communication Between Two Reservoirs Using Advanced Numerical Well Testing Model
Authors: Al-Wehaibi B. A. , Anisur Rahman N. M. , Issaka M. B. 
Published: July 2016

Abstract
The inter-reservoir communication plays a major role in the dynamic performance of any reservoir. Hence, characterizing and understanding the degree of the communication is essential in modeling the reservoir behavior. This paper demonstrates the power of the pressure transient tests in successfully detecting and characterizing the communication between two reservoirs separated by a very thin tight layer as a case study. It also presents the results of integrated pressure transient analyses for long build-up tests conducted in one of the wells, the data of which was acquired from the PDHMS. These confirm the inter-reservoir communication in this field. Using a numerical interpretation technique, a rigorous multi-layer model has successfully matched the pressure transient data and has helped estimating the degree of the communication between the two reservoirs. It has also allowed characterizing the thin tight layer that separates the two reservoirs and controls the inter-reservoir hydraulic communication. This work will help the simulation models of the field to quantify the degree of the communication and capture the real performance of the reservoirs in order to achieve better and effective reservoir management and development plans.
Single-Well Chemical Tracer Test for Residual Oil Measurement: Field Trial and Case Study
Authors: AlAbbad Mohammed , Balasubramanian Senthilmurugan , Sanni Modiu , Kokal Sunil , Zefzafy Ibrahim , Adam Frederick , AlHajji Adnan 
Published: July 2016

Abstract
Tracers are increasingly being deployed as an effective reservoir monitoring and surveillance (M&S) tool in the oil and gas industry. In particular, the single-well chemical tracer test (SWCTT) is being widely used to estimate remaining oil saturation (ROS) or residual oil saturation (Sor), especially in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations. The test provides a direct measure of ROS in a wider reservoir volume compared to the measurements made by near wellbore logs or cores.
A SWCTT was designed and implemented in a carbonate field to determine fluid saturations. The reservoir is heterogeneous with layers of high to low permeability limestone, porosity in the range of 20–30%, and interspersed with patchy layers of dolomites and a very competent anhydrite seal. The SWCTT was conducted in a very mature part of the field near the peripheral water injectors, to determine the residual oil saturation before a planned IOR pilot test.
This paper presents the complete design and implementation of the test, operational challenges, and the analyses and interpretation of the results. The depth of investigation was 13–14 feet from the wellbore. Laboratory results of determining the partitioning coefficient of the chemical tracer are described and presented. The design of the tracer test taking into consideration the reservoir properties are shared. Considerable operational challenges in the field and appropriate solutions to overcome them provide a very interesting case study. The returns and analyses of the samples provided a unique set of data that were interpreted using a simple analytical tracer model which was comparable to the reservoir simulations predictions. The Sor was obtained after fitting the tracer return data to a model of the classical convection-dispersion equation. The results indicate that there was no displacement or drift that occurred during the shut-in period. The mass balance of the tracers suggests that more than 98% of the tracers were recovered with negligible tracer adsorption during the test duration. The results are in close agreement with a similar test benchmarked independently by a commercial vendor using a different injection design scheme.
Geochemical Monitoring Plan for the First CO2-EOR and Sequestration Project in Saudi Arabia
Authors: Balasubramanian Senthilmurugan , Sanni Modiu , Kokal Sunil , Oduro Harry , Yu Haichao , Al-Hajji Adnan , Adam Frederick 
Published: July 2016

Abstract
Saudi Aramco is implementing its first carbon-dioxide enhanced oil recovery (CO2-EOR) carbon capture, utilization and storage (CCUS) demonstration project in a small depleted part of a carbonate reservoir, as part of its environmental stewardship and its efforts to mitigate CO2 emissions. It is worth mentioning that Saudi Aramco does not require EOR oil for many decades to come. This project is being implemented primarily to demonstrate the feasibility of sequestering CO2 through EOR in the Kingdom and using it as grounds to test new monitoring and surveillance (M&S) technologies. The injected CO2 is expected to react with formation fluid (oil and water) and rock minerals for geological storage to occur. Reservoir simulation studies suggest about 40-50% of the injected CO2 will be sequestered permanently in the reservoir.
To understand the geological trapping process and also to identify and quantify any inadvertent "out-of-zone" CO2 leakage, a comprehensive geochemical monitoring (geochem) program has been developed and is being deployed. The objectives of the geochem program are to monitor the project before, during and after CO2 injection to assess the efficacy of the sequestration process. In addition, the geochem data will provide the pertinent information for calibrating the CO2 reactive transport model to be used to quantify and predict the amount of CO2 that will be sequestered over a long period. The geochem plan includes monitoring the changes in basic ionic compositions of reservoir and aquifer water, pH, dissolved organic carbons (DOCs), volatile organic carbons (VOCs), BTEX, etc., and changes in isotopes of carbon, oxygen, hydrogen. Furthermore, the plan also includes monitoring the changes in soil gas (CO2, CH4, O2, Ar, Rn, and He) concentration.
Baseline and time-lapse data are being collected. These provide the basic input to our reactive transport model. The results from the analyses of the reservoir fluid indicate very little value may be derived from monitoring time-lapse isotopic changes. Isotope clumping is considered as a better approach to understand and quantify the amount CO2 being sequestered. This paper reviews the design and implementation of the geochem plan for the project, operational issues, the results obtained to date and the use of "clumped-isotope" geochemistry. Plans for further implementation of the geochem program and the lessons learned will be shared. The geochem plan is deemed robust and will help with understanding, tracking, monitoring and predicting the geo-sequestration process.
First Successful Installation of a 4-1/2 Pre-Perforated Liner through a 5-1/2 Solid Expandable Liner
Authors: Al Rubaii Mohammed Murif , Shehri Hasan H. , Nwachukwu Cosmas N. , Andrews Stacey , Atallah Yasser 
Published: July 2016

Abstract
Sustaining field proven technologies in mature fields and maximizing Return of Investment (ROI) is a priority for operators worldwide. Financial constraints such as oil and gas prices, drilling cost, and any intangibles must not burden the success of pushing limits to open new horizons, not just for the present time but also for future generations. Parallel to reaching new limits, we must keep an eye on the safety and engineering behind any step taken toward the limit to push the envelope successfully. Drilling team recently used a a vendor product to maximize production, isolate a loss circulation zone, and push the operating envelop by installing the first 4-1/2" open hole completion (Pre-perforated liner) with inflatable open hole isolation packers through a 5-1/2" × 7" open hole liner (OHL). The vendor product enabled Saudi Aramco to install 5-1/2" × 7" solid expandable liner installation. The 5-½" 18.24 lb/ft solid expandable systems was utilized to isolate a loss zone and reactive shale section, sealing off the problematic interval and allowing an extended lateral section to be drilled through the reservoir. The expandable liner was run through a window cut through 7" 26 lb/ft casing and subsequently installed across part of the curve section to isolate the lost circulation zone. The use of the expandable liner enables the ability to drill the remaining build section and horizontal section together with full circulation. This paper describes the challenge and application.