bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Stimulation Design Using Hydrajet Fracturing Process with Coiled Tubing in Saudi Arabia Gas Well
Authors: AlBuali Muhammad , AlDuaij Ahmad Naif , Hardegger Bruno , Bastisya Muhammad Gusti , Khan Faisal 
Published: February 2017

Abstract
A successful evaluation and development program in a tight gas-bearing formation requires considerable analysis, not to mention optimization to help ensure a profitable income. In time where problems arise and impact the performance of the well during completion, the risks of well intervention increase significantly. These problems sometimes are not allowing a hydraulic fracturing treatment to be performed. In a situation where hydraulic fracturing treatment is not feasible, an optimized stimulation design is needed to guarantee commercial gas production from the well within current completion constraints and allocated budget.
In the attempt to find an economical yet effective stimulation solution, the hydrajet fracturing process was chosen to be implemented. This stimulation technique has a proven success rate in onshore applications. To increase the treatment efficiency, a novel acid-soluble abrasive material was used to connect the reservoir to the wellbore, which helped avoid sand cleanout time and use of additional chemicals. It was followed by a pinpoint acid stimulation to unlock the hydrocarbons in a low-pressure area of the reservoir.
The post-treatment result showed a very promising result with the gas rate achieved, which was approximately double the rate expected by a conventional bullhead acid fracturing treatment. This has demonstrated the value that the technique brought to the industry.
This paper discusses not only the result of the technique compared to wells that are completed and evaluated with different completion schemes, but also presents a best practice for the method used to stimulate a well. The success of this operation resulted in providing an alternative to completing their requirements relatively faster and more cost-effectively.
New Approach to Modeling Your Reservoir: A Technique Based on Understanding Modern Deposits, Outcrops and Well-Log Data
Authors: Amer Aimen 
Published: February 2017

Abstract
The main objective of this study was to build a 3D geological model that will allow geologists to be able to better understand facies distribution based on a deep comprehension of depositional model concepts. The goal is to allow the geologist to walk into and traverse in real time such model. This may seem out of the norm, but by the end of this paper you will be able to appreciate this new technique.
The case study that is presented in this article is focused on the Ferron Sandstone Member exposed at the Muddy Creek Canyon located in Utah, USA. Seven vertical wells have been drilled, cored and logged behind the valley walls. Beside basic openhole logs, two wells have been logged with borehole image logs. Detailed outcrop traverses have been performed along the Muddy Creek Canyon area and surface topography along with subsurface facies variations has been captured and integrated with modern day fluvial systems observations from Trinity River, Texas, USA. The latter has served as a modern day analog for parts of our model.
The modeled facies range from deep marine shales, shoreface deposits and delta deposits, all the way to fluvial, swamp and lagoon facies. Sea level fluctuations have been captured and modeled in a sequence stratigraphic fashion.
The model that is produced does not just integration surface and subsurface data into a single 3D geological model, but it also incorporates the concept of sequence stratigraphy and sea level fluctuations. Such approach allowed the comparison between the 3D model, the actual outcrops and modern depositional processes. A number of iterations had to be performed on the model to reach to an actual representation of the outcrops and subsurface data. This was done by taking the model to the outcrop in order to quality check the actual distribution of facies, hence "walking in the model".
The value of doing such exercise is to develop a deeper understanding on reservoir distributions, lateral changes in facies and depositional environment variations, in the subsurface and apply these learnt concepts on oil fields. By doing so, the geologist has a better chance in reducing uncertainties associated with reservoir, seal and source rock distribution, increasing the change of finding hydrocarbon.
Coffee as a Cement Retarder
Authors: Jadhav Rahul , Sen Tamal K. , Deshprabhu Sumukh 
Published: February 2017

Abstract
Retarders are one of the most important additives in oilwell cementing for achieving the desired pumping time of cementitious slurry. Retarders are mainly extracted from natural sources, or they are chemically synthesized. However, synthesized retarders can have significant environmental effects. This paper proposes using coffee powder as a biocompatible retarder in oilwell cementing.
This paper discusses a study wherein coffee powder was used as a cement retarder and its effect on other cement slurry properties was evaluated. Cement slurry was prepared and tested as per API RP 10B2 (2005) procedures for thickening time, compressive strength, fluid loss, and rheology. The performance of coffee powder was tested at various concentrations and temperatures up to 350°F. Its retardation activity was compared to a commonly used lignosulfonate-based retarder as well as a synthetic retarder.
Coffee powder exhibited a predictable and linear thickening time behavior with respect to concentration and temperature variation. Testing at different temperatures revealed that coffee powder alone can be used at temperatures up to 350°F without need for a retarder intensifier. A concentration sensitivity study was performed at 125°F, and the coffee powder displayed expected results. To achieve similar performance, lower amounts of coffee powder are necessary compared to the lignosulfonate-based retarder. The performance of coffee powder was similar to the synthetic retarder. Furthermore, coffee powder does not cause adverse effects on other cement slurry properties, such as compressive strength development, fluid loss, and rheology.
This work presents coffee powder performance as a cement retarder. Coffee is readily available, and it demonstrates a high performance and linear concentration response without hampering other cement properties.
Direct Observation of Low-Salinity Water Effect: Relationship Between Micro-Dispersion Formation and Wettability Alteration
Authors: Facanha Juliana M. , Mahzari Pedram , Sohrabi Mehran 
Published: February 2017

Abstract
Improved oil recovery by low salinity water injection (LSWI) has been linked to wettability alteration. However, the main causes behind this are still debatable. Recently, formation of water-in-oil micro-dispersions has been put forward as the predominant mechanism behind the additional oil recovery by LSWI. This work aims to investigate the role of micro-dispersion formation in wettability alteration by LSWI by performing a series of contact angle measurements.
A dynamic contact angle measurement technique was designed and performed on aged quartz substrates. The substrates were first covered with high salinity brine and then several oil drops were deposited on the substrates to assess the initial wettability of the substrates. Then, the high salinity brine was gradually replaced by a low salinity brine to obtain the response of the same droplets to reduction of water salinity. This approach enabled analysis of wettability alteration due to LSWI. Four crude oil samples with various tendencies to form micro-dispersion were used. Also, two blends of positive and negative crudes were used to test if adding a crude oil with surface active components could make apoor crude oil responsive to low salinity water. A positive oil isa crude oil that forms micro dispersion and a negative oil is one that does not.
It was observed that there was a shift in wettability from mixed-wet and weakly-oil wet towards a more water-wet state once the high salinity brine was replaced by low salinity for the oils that were prone to formation of micro-dispersion. An average change of 10-20° in the value of contact angles was observed for these oil samples depending on initial wettability. However, the contact angles did not exhibit any detectable change for the oils with a weak tendency to form micro-dispersion. Furthermore, the mixing of positive and negative oils resulted in considerable changes in contact angles for the blended oil, which demonstrated the importance of polar components in the wettability alteration process caused by LSWI. In conclusion, the results indicate that the formation of micro-dispersion and the initial wettability are two dominant factors that determinethe outcome of LSWI.
Asphaltene Chemistry Across a Large Field in Saudi Arabia
Authors: Abdallah Wael , Pomerantz Andrew E. , Sauerer Bastian , Mullins Oliver C. , Buiting Jan 
Published: February 2017

Abstract
Using laboratory and downhole fluid analyzers, it is possible to characterize lateral and vertical variations in reservoir fluid composition. Previous application of those measurementes have revealed wide spatial variations in the concentrations of asphaltenes in crude oil for many reservoirs. However many of the chemical attributes of asphaltenes have been very difficult to determine and require careful assessment. One of the industry's interests in this class is due to their interfacial activity, an important attribute related to fluid flow in the reservoir and ultimately to recovery of the crude oil. It is very desirable to get a better understanding of the spatial variation of asphaltene chemistry throughout the formation.
The aim of this work was to analyze chemical properties of asphaltenes using established spectroscopic techniques including Raman spectroscopy, laser desorption laser ionization mass spectrometry (L2MS), surface-assisted laser desorption ionization (SALDI) mass spectrometry, sulfur x-ray absorption near edge structure (S-XANES) spectroscopy, and nuclear magnetic resonance (NMR) spectroscopy. The samples were obtained from different locations in the Ghawar field all separated by more than 20 km from each other. The asphaltene chemistry of these samples was found to be typical and simple models for the asphaltenes are applicable. In addition, the asphaltenes from the samples are rather uniform, with an asphaltene structure showing a central island of aromatic rings with an average diameter of 1.48 nm (i.e. 7 to 8 aromatic rings) and a molecular weight in the range of 600 to 750 g/mol for a single asphaltene molecule. This matches other findings regarding asphaltenes in Saudi Arabian reservoirs. The implication is that models for wettability and fluid interfacial tension that rely on simple asphaltene characterization are plausibly beneficial.
Decoding the Seismic Signal: A Comprehensive Approach for Carbonate Buildup Imaging in the Red Sea, KSA
Authors: Escalona Luis , Saleh Saleh M. 
Published: February 2017

Abstract
The seismic data set provides geological information from stratigraphic boundaries. Commonly, different responses are reflected in terms of amplitude, phase and frequencies changes. The bandwidth of the seismic signal and processing approximations restrict the subsurface resolution. Several techniques such as seismic inversion, spectral decomposition, coherency processing has been developed to extract geological information from the seismic data, to reveal the subsurface geology and evaluate reservoir targets. This work summarizes different workflows to improve seismic imaging and provide better reservoir characterization of carbonate buildups in the Red Sea.
The process started in terms of whether the seismic attributes below the salt are robust enough to enable a seismically driven carbonate characterization. Extensive gather analysis, velocity corrections and data conditioning was performed at pre and post stages. Employing HD spectral decomposition, elastic inversion, interactive geobody extraction and integration of well data (core analysis) a successful qualitative and quantitative reservoir characterization was reached.
Virtual Geosteering
Authors: Alsanie Faisal S. , Khudiri Musab , Talhah Nezar A. , Bin Abdulrahman , Rayan H. , Muhammad Kashif , Ashraf Hamood M 
Published: February 2017

Abstract
In the context of current oil price volatility, every operator is trying to apply technologies to reduce the cost of the drilling phase of their horizontal operations, whereas the interpretation application holds a vast portion of success rate in geosteering.Making geosteering functions more important to achieve the optimum production target. The advancement on the utilization of real time data and modeling data in various systems are introducing more critical operationaldecisions based on these systems.
The new virtual geosteering system allows moving from complex multiple systems to a real time data solution with advance geological interpretation that supports a highly available collaborative virtual working environment for geoscientist and engineers during operations.
A virtual geosteering system makes data available in a customized cross-section visualization, where it can be paired with real-time measurements while drilling and logging while drilling (LWD) information. This paper will explain the advantages of this process, with a focus on the flow of data to and from the earth model. It will also focus on additional add-on tools, required to effectively run the remote geosteering process on a single system, through integrated workflows. Virtual geosteering improved collaboration between geologists and drillerswhere critical formation information can be made easily available to be prepared for wellbore condition changes.
Furthermore, advance interpretation tools that allows the data integration between different data sources making it possible to have a unified visualization system to support complete a suite for geosteering and modeling in the same time.
Best Practices to Prevent Stuck Pipe Incidents in Offshore Shaly Formations
Authors: Aljubran M. J. , Al-Yami A. S. , Madan M. A. 
Published: February 2017

Abstract
Under this climate of oil price and energy uncertainty, it is mandatory to limit the non-productive time (NPT) and achieve the highest levels of operational excellence. This is a key factor toward overcoming the evolving economic challenges, reducing budget and spending, and optimizing the return on investment. Worldwide, stuck pipe and borehole problems represent one major contributor into the NPT while drilling, reaming, tripping, casing and running completions. This NPT category becomes even more critical when dealing with shaly formations. Saudi Aramco constantly deal with offshore shaly formations in Saudi Arabia where stuck pipe and borehole problems contribute with over 24% to the overall drilling and workover NPT. Establishing best practices to minimize or prevent these problems will enhance the overall drilling performance and result in significant operating time reductions and cost savings.
The major offshore re-entry operation challenges are first screened: formation instability, hole size, well trajectory, bottomhole assembly and experience and communication. The shaly formation rock nature is analyzed to understand the stressed shale instability root cause: mechanical and/or chemical. This diagnostic step establishes the formation shale properties and behavior. In relation to this information, three basic stuck pipe mechanisms (pack-off and bridging, differential sticking, and wellbore geometry) are discussed where the major contributing factors for each category are identified. This leads to the establishment of proactive recommendations and best practices.
These practices will tackle the problem from different angles to construct an integrated solution. This includes drilling fluid design (rheology, filter cake, filtrate volume and properties, etc.), hole cleaning (rate of penetration, sweep pills, bottoms-up volume, etc.) and drilling parameters (trend analysis, flow rates, string motion, etc.). This paper will highlight the recommended practices and provide actual well examples where stuck pipe tendency was reduced in shaly formations.
Senlac, The Forgotten SAGD Project
Authors: Delamaide Eric 
Published: February 2017

Abstract
The Senlac SAGD (Steam-Assisted Gravity Drainage) project is Saskatchewan, Canada, does not have the same name recognition as its much bigger brothers in the Alberta Oil Sands but it certainly deserves to be known better. Senlac was the first industrial SAGD project in Canada back in 1997 and since then it has been the site for other technological innovations such as the use of solvent in addition with steam to increase recovery and reduce the Steam Oil Ratio, as well as the testing of wedge wells – wells drilled between SAGD well pairs to benefit from the heat remaining in the reservoir.
The reservoir in Senlac is the Dina-Cummings of Lower Cretaceous age and is much smaller than the McMurray formation which is the site of most of the large-scale oil sands project but the oil is only 5,000 cp thus it is mobile at reservoir temperature. This is a significant difference which allows well pairs to achieve excellent production and recovery even though reservoir thickness is only 8-16 m, well below the standard cut-off for SAGD. The presence of bottom water under parts of the field is an added challenge to the operations.
The paper will present the field characteristics and production performances as well as the main technological developments such as the Solvent Added Process and the use of wedge wells.
The paper will present a complete case study of a SAGD project in a heavy oil reservoir where oil is mobile. Most SAGD project so far have been conducted in bitumen but the paper will show the potential for this technology in thinner and smaller reservoirs.
Power Cost Optimization Using Data Analytics-Based Load Forecasting in Upstream O&G Operations
Authors: Hughes Justin T. , Silvia Shejuti , Ahmad Wajdi 
Published: February 2017

Abstract
Oilfield power demand is extremely dynamic in both time and space, and a lack of accurate forecasting causes increased cost for electric utilities to extend their grids to the field. It also causes increased demand charges for producers, which increases their lifting costs. As well production declines with time, electric utilities may end up with stranded assets which represent a large investment that is costly to maintain but is not being fully utilized. Therefore, both producers and utilities have a common interest in improved load forecasting to cut down on cost of power, especially during times of low oil prices. In this research, we show how data analytics can be used to predict load growth evolution in time and space. We incorporate production operational data, well location and geometry, and historical power consumption of neighboring wells into a data analytics engine to develop a platform for improved oilfield load forecasting. This data-driven approach is shown to decrease a utility's kilowatt prediction error for new well pads by 48 to 78% for annual average power and by 10 to 26% for peak power.
Optimisation and Design for WAG-CO2 Combined with Soft Micro Gel SMG in Complicated Carbonate Reservoirs Containing with High Permeability Streaks
Authors: Dandan Hu , Yuanbing Wu , Xiaocui Gao , Songhao Hu , Mingsheng Feng 
Published: February 2017

Abstract
Carbonate reservoirs in the Middle East are highly heterogeneous with great reservoir physical property difference in longitudinal direction, water breakthrough easily caused by high permeability streaks when the reservoirs were put into commingled production. This paper concerns a highly layered gas cap carbonate reservoir with an Upper zone and a Lower zone, which has been developed for nearly 60 years with recovery factor by 16% and water cut by 12% and remained about 52% recoverable reserve in tight zones. Nearly 40% undeveloped reserves of the oilfields lied in low permeability reservoirs, which has low well productivity with vertical well and achieved low sweep efficiency by waterflooding due to high permeability streaks. Horizontal well technology has been or will be implemented for these low permeability reservoirs to enhance well productivity in succession and WAG-CO2 combined with Soft Micro Gel (SMG) (140°C temperature resistance, 300,000 mg/L salinity tolerance) can plug off large pore throat and high permeability streaks.
The paper completed preliminary screening of CO2 WAG process for the reservoirs in B oilfield based on reservoir parameters, empirical principal, laboratory physical simulation experiment and numerical simulation. The paper optimized horizontal well pattern for the reservoirs simultaneously for horizontal waterflooding and the CO2 WAG process. Multi-parameter sensitivity analysis has been completed to establish the empirical model for the relationship of well spacing and recovery factor by CO2 WAG process. Simulation models also have been built up with relevant data of the reservoirs to provide the optimum ratio of CO2 to water, CO2 injection timing and CO2 injection rate. The paper also compared WF and CO2 WAG combined with Soft Micro Gel (SMG) through modelling result. Soft Micro Gel (SMG) can assist CO2 WAG to achieve better results and enhance vertical sweep efficiency. CO2 WAG combined with Soft Micro Gel (SMG) can enhance recovery factor by 12% to 18% for the carbonate reservoirs containing with high permeability streaks and is the most effective EOR method whether or not previous water flooding.
The study in the paper provides important EOR reference for other similar reservoirs in Middle East to achieve high ultimate RF after WF.