bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach for Modeling Scale Formation during Water Injection into Carbonate Reservoirs
Authors: Lu Peng , Wang Qiwei , Chen Tao , Chang Frank 
Published: July 2016

Abstract
Water injection is commonly used in oil fields for pressure support and productivity enhancement. Injection water, if incompatible with formation water, can induce scale precipitation and impose a significant threat to economic and efficient field operation. Reliable scale prediction is of critical importance for the selection of suitable injection water and development of an effective scale management strategy.
The traditional (thermodynamic) approach for scale prediction only provides precipitation potential at different mixing ratios. It describes the initial and final states of the system and omits some intermediate processes and products that may be important for operations. In addition, it may overestimate the total amount of the scale forms. In this paper, we describe a new approach, the kinetic approach, to facilitate more accurate prediction of scale formation.
We demonstrate the kinetic approach in a parametric study of seawater injection into a carbonate reservoir in Saudi Arabia using Reactive Transport Modeling (RTM). RTM simulates coupled multiphase fluid flow and chemical reactions, and has the capability of predicting time-dependent mineral scales formation and associated reservoir quality deterioration. Formation of calcium sulfate scale in the reservoir and near wellbore is a major concern due to high calcium concentration in formation water and high sulfate concentration in the seawater. We built a two-dimensional RTM using TOUGHREACT v1.2 with GUI pre- and post-processor PetraSim v2015, and simulated scale formation over a 20-year time span. Reservoir heterogeneities was considered in our model. The impact of scale formation on the reservoir and well properties during waterflooding operations was evaluated.
The results indicate that the migration path of the solutes depends highly on the reservoir permeability distribution; preferential flow paths form in the high permeability layers. At 20 years, up to 11.6% anhydrite scale forms in the mixing zones of injection and formation waters and up to 18% calcite scale forms near injection wellbore (~ 10 m radial distance to the wellbore). Severe porosity reduction is predicted near the injection wellbore and in the mixing zones at 20 year due to the formation of calcite and anhydrite scales, respectively. A negative feedback forms between the initial exploitation of preferential flow paths and subsequent reservoir quality deterioration in these paths.
The kinetic approach described in this paper will offers a significant improvement on scale prediction results over the traditional approach for field development and cost-effective scale management strategy.
Design Optimization of Multilateral Wells in Heterogeneous Reservoirs
Authors: Ayokunle Ajayi Temitope , Hashem Mohamed Hossni 
Published: July 2016

Abstract
Maximizing profit with minimal costs is a top priority in the oil and gas industry. With the dynamics of today's oil market, finding economically feasible tools to maximizing the production is vital. Multilateral wells possess the potential of achieving such a goal. To date, different theoretical designs of multilateral wells are proposed in literature. One of the most common designs studied is the fishbone configuration. This configuration maximizes the reservoir contact and thus the productivity of the well. While the merits of the application of multilateral wells are well documented, an understanding of the best operating conditions for the use of multilateral wells is rare thus we answer cogent questions related to the optimization of multilateral wells under different reservoir conditions and well design parameters.
To answer such questions, Design of Experiment (DOE) and Response Surface Methodology (RSM) was utilized. Selected factors to be optimized are the number of laterals, length of horizontal sections of laterals, correlation lengths for heterogeneity indication, reservoir thickness, and permeability anisotropy. These factors were chosen based on literature search, perceptions and deliberations while the objective function is the cumulative oil production. Several experiments were conducted using extensive three dimensional fine scale numerical simulations and the Box Behnken response surface methodology was used to derive the response surfaces. Single effects and interaction plots are made to show the interactions between parameters and the effect of these parameters and interactions on the objective function.
Results show a high dependence of productivity on the horizontal section length and reservoir thickness. This implies that candidate reservoirs for the application of fishbone multilateral wells should possess larger thickness. However, where the reservoir is thin production can be improved using longer horizontal sections. The outcome of this study indicates the importance of the horizontal section and lateral lengths on a fishbone multilateral well productivity from the same reservoir.
This study provides a template for decision making in field development operations thereby reducing uncertainties and maximizing gains.
Coupling Memory-Based Diffusivity Model with Energy Balance Equation to Estimate Temperature Distributions During Thermal EOR Process
Authors: Hassan Amjed M. , Hossain M. Enamul 
Published: July 2016

Abstract
At the end of the primary recovery phase, enhanced oil recovery (EOR) process such as hot water flooding becomes more attractive to reduce the residual oil saturation and to increase the oil production. It is well known that during hot water injection, the heat transfers from the injected fluid to the reservoir matrix, and this transfer depends mostly on the rheological and thermal properties of the formation rock and fluids. Moreover, the injection time and fluid velocity play significant roles on the temperature distribution. Therefore, it is important to investigate the effects of fluid velocity on the temperature distribution during thermal operations. The temperature profile in a reservoir formation is an important indicator of various reservoir conditions, such as type of fluid encroachment, the state of water or gas influx, etc. This information is necessary for better reservoir management. Previous studies assumed constant fluid velocity throughout the reservoir to calculate the temperature variations. However, this work studies the temperature distributions of reservoir rock and fluid during thermal operations by employing the velocity profiles.
The temperature distributions are estimated by coupling a proposed memory-based diffusivity model with energy balance equation. The variations of fluid velocity are produced by solving the memory-based diffusivity equation, and then the temperature distributions are estimated based on the fluid velocity profiles. The proposed energy balanced equation is solved by a newly developed numerical technique. This technique is used to couple the energy balance equation with the memory-based diffusivity model. The model equations are solved simultaneously together by Matlab programming language. The temperature profiles are analyzed for unequal rock and fluid temperatures throughout the reservoir.
Results show that, coupling of the pressure model and temperature model can lead to more reasonable temperature distributions during thermal flooding and then to better design of such operations. In addition, it is found that temperature distributions are affected mainly by the pressure variations and the fluid velocity. The finding of this research will help to improve the performance/efficiency of thermal flooding operations.
Enhanced Petrophysical Interpretation of 3D Electromagnetic Surveys for Reservoir Characterization
Authors: Alsaif Sarah F. , Alkhatib Ali M. , Marsala Alberto F. 
Published: July 2016

Abstract
Increasing the recovery factor of brown fields is one of the key challenge for oil companies. When production is driven by water injection, monitoring flood front movements reservoirs is crucial to optimize field production strategies. Most reservoir characterization and saturation tools provide data at specific locations in the reservoir, with a limited radius of investigation around the wellbore. One promising approach to map and monitor the saturation distribution is to deploy 3D electromagnetic surveys. These methods provide an indirect way to determine the saturation by measuring the spatial distribution of resistivity in the inter-well regions.
One of the main challenges in the interpretation of electromagnetic methods is the uncertainty in our knowledge of the reservoir properties in the inter-well regions. These properties are necessary to derive saturation maps from resistivity measurements. This study introduces a novel approach to interpret electromagnetic surveys, producing robust saturation maps that can guide reservoir management practices. The described workflows apply dynamic simulation and advanced uncertainty quantification. The main uncertain parameter that is considered in the proposed approach is permeability, which is assumed to be a spatial parameter. The probabilistic collocation method was applied to efficiently quantify uncertainty in permeability and its effect on the salinity distribution. The outcome of this method is a polynomial proxy model that can be used to perform statistical analyses using a significantly large sample set with minimal computational cost. The results obtained showed that it is possible to investigate a wide range of uncertainty in a computationally efficient manner, providing more robust saturation maps compared to current practices.
Causal Factor Analysis – The Missing Puzzle Piece
Authors: Perkinson Larry 
Published: July 2016

Abstract
There are few if any systems in use to categorize and analyze the causal factors leading to significant incidents. This presentation explores a new categorization methodology and provides causal factor data analysis of real incidents that shows how the process contributes to improving safety.
Detailed accident investigation reports were reviewed from 40 major incidents containing literally hundreds of causal factors. Repeated passes were made through the causal factors to identify commonalities. Thirty-two discrete categories of causal factors were identified. Detailed definitions were written and multiple examples provided for each category. The categories were then tested with a new set of causal factors to ensure they were both exhaustive and mutually exclusive. The twenty-eight final categories were then put into question form for future conversion to an expert system.
The analytical advantages of the categories were tested with a group of five major crane incidents from around the world. The incident reports were reviewed and the causal factors identified. The methodology was used to categorize the causal factors and a Pareto chart was developed. This simple chart allowed the discovery of repeated causal factor categories and uncovered where corrective actions for identified root causes of the casual factor categories were inadequate.
This methodology not only assists the users in categorizing causal factors, it assists in identifying generic causes (cuts across organizational boundaries) and assessing the effectiveness of corrective actions for root causes. It has also formed the basis for building an expert system to identify causal factors, which is currently under development.
Comprehensive Traffic Safety Program of Saudi Aramco Safaniya Onshore Producing Department SOnPD Reduces Fatal Traffic Accidents in the Khafji and Nuayriah Areas
Authors: Rahman Syed Obaidur 
Published: July 2016

Abstract
As directed by the Vice President, Northern Area Oil Operations (NAOO), Safaniya Onshore Producing Department (SOnPD) developed and implemented a comprehensive Traffic Safety Program with the objective to eliminate or minimize traffic related accidents in the Safaniya area. The scope of this committee covered highways and major local roads from Jubail Bridge on Abu Hadriya highway up to Khafji City. Successful implementation of this program has resulted in significant improvement and has minimized traffic related accidents. The reported statistics by six NAOO departments operating in Safaniya have reported a reduction of 90+% in MVAs involving company vehicles, 70+% in private motor vehicle accidents, and over 60% reduction in Fatalities. For Safaniya Onshore Producing Department (SOnPD), the leading Department, fatalities and accidents involving company and private vehicle in the area are eliminated. On the otherhand according to government statistics, between the years 2010-2012 and 2013-2015 vehicles incidents in Khafji and Nuayriay areas saw a reduction in fatalities by 11%, i.e., 10 lives/yr were saved.
A Rigorous Correlation for Quantitative Prediction of Water Cresting in Multi-Fractured Horizontal Wells
Authors: Mahboob Ahmad , Al-Nuaim Sami , Rammay Muzammil Hussain 
Published: July 2016

Abstract
This study uses Artificial Neural Network (ANN) to develop correlations for estimating critical oil rate in multi-fractured horizontal wells (MFHWs) with water cresting issue.
A programming software was coupled with a commercial simulator to develop the correlation using a black oil model with typical rock, fluid and reservoir properties. The effects of reservoir fluid properties, fracture properties, water oil contact, horizontal and vertical permeability and length of the fractures were investigated in comparison with the base case and the results were converged to form empirical equations for calculating critical oil rate.
The proposed correlation is dimensionless and can be used for any multi-frac horizontal well and are function of fracture height, permeabilities, fracture conductivities and fluids' densities. All observations of this correlation complies well with the general trends e.g. low anisotropy ratio, lesser fracture conductivity and high viscosity delayed the water breakthrough. Higher anisotropy ratio and low viscosity increased critical oil rate. The results obtained from this correlation when compared with simulated data set had an absolute percentage error of and standard deviation of for critical oil rate correlation, which is quite satisfactory.
Most of the work in literature has been done for water-coning in naturally fractured reservoirs and in some limited aspects of hydraulically-fractured reservoirs, but there is a need to estimate water cresting in MFHWs in order to support early production strategies. This correlation can add value to oil and gas industry in terms of time and money.
Measurement of Bubble Point Pressures of n-Decane, CO2 and N2 Mixtures
Authors: Hassan Mohamed , Gajbhiye Rahul N. , Sultan Abdullah S. , Abu-Khamsin Sidqi 
Published: July 2016

Abstract
Utilization of carbon dioxide in enhanced oil recovery (EOR) serves two important goals. Firstly, it recovers more oil, which could not be recovered during primary and secondary recovery methods. Secondly, it is one of the carbon capture and sequestration (CCS) techniques that work to reduce the emissions of greenhouse gases into the air and combat the climate change. To design and optimize the process of CO2-EOR, it is crucial for engineers to have knowledge about the reservoir fluids properties and their interaction with injected gases. Bubble point pressure is critical for the description of the reservoir fluid behaviour.
Constant composition expansion (CCE) experiments were performed to measure the bubble point pressures for binary mixtures of n-decane/carbon dioxide (n-C10/CO2) and ternary mixtures of n-decane/carbon dioxide/nitrogen (n-C10/CO2/N2). The n-decane represented the hydrocarbon phase, where the gaseous phase consisted of CO2 and N2. The experiments were conducted at two different temperatures, 30 and 60° C. The gas mole fraction in each mixture ranged from 20-80%. For the gaseous phase itself, N2 and CO2 were mixed in three different proportions: 0, 10 & 20% N2 mole fractions. The work in this paper was set to examine how the bubble point would behave due to presence of nitrogen contamination in carbon dioxide, rise in temperature and changing mixture compositions.
The results shows that bubble point pressure increased when the temperature increased from 30° to 60° C, for all mixtures. These increases in bubble point pressures ranged between 19-35%. The introduction of N2 into the mixture would raise the bubble point by up to 55%. The addition of more hydrocarbon into the mixture decreased the bubble point. Bubble point pressure is a strong function of gas solubility, which is capable to explain these behaviors of bubble points.
Modeling the Role of Wettability Alteration with Brine Composition and Increased Oil Recovery from Carbonate Cores
Authors: Alshakhs Mohammed J. , Kovscek Anthony R. 
Published: July 2016

Abstract
Laboratory studies have shown that certain modifications to the ionic composition of the injection water increase oil recovery from carbonates. The impact of salinity is related to wettability alteration of the system toward more water wetness, demonstrated by a reduction in the measured oil-water contact-angles. It is not confirmed that the wettability shift contributes to all or most of the oil recovery increase. This is mainly because conventional multiphase fluid flow simulators, commonly used to predict oil recovery, do not incorporate directly the role of wettability conditions and contact-angles. This paper provides a new method to estimate the additional oil recovery that results from wettability alteration of carbonate cores.
A pore network model (PNM) was used to predict relative permeability curves at different wettability conditions. The effect on oil recovery was quantified from imbibition relative permeability curves that were generated from the PNM. These curves were used to simulate displacements. The simulation was run using a brine tracking function that estimates the instantaneous relative permeability based on tracing the injection brine salinity. The proposed approach was applied to the experimental core-flood experiments reported by Alshakhs and Kovscek (2015a).
The PNM was constructed for a representative bimodal carbonate system. A drainage capillary pressure curve from a mercury injection experiment guided the construction of the static model structure. The static PNM model generated two relative permeability sets that correspond to contact-angles of 95° and 55°. The simulation results showed comparable additional oil recovery to observations from the experimental core-flood experiments, 7.5% compared to 6.4%, respectively. The good match supports that the additional oil recovery is mainly attributed to wettability alteration.
Implementation of Chemical EOR as Huff and Puff to Improve Oil Recovery for Heavy Oil Field by Chemical Treatment SEMAR Cast Study Bamboo Oil Field
Authors: Farog Ali , A.Mustafa Haytham , Mukhtar Enas , Elblaoula Husham , A. Yassin Badreldin , Tagwa Musa , Mucharam Leksono , Abdalla Fadul 
Published: July 2016

Abstract
Bamboo field is located in block 2A Muglad Basin covers an area of 144 Square km. It consists of multi block, multi-layered under-saturated sandstone reservoir of late Cretaceous ages barried at depth ranging from 1000 m to 1700 m with crude oil viscosity ranges from 70 cp to 3000 cp. The total Field STOIIP and Recovery Factor (RF) are currently estimated at around 506MMSTB and 18% respectively through primary depletion. Up to date; the field had recovered more than 75% of the EUR.
The field initially produced around 20,000 STB/Day with early water breakthrough and very minimal gas production rate until today. However the production rate declined rapidly when the water production rate increased. Major factors that contributed to this problem are possibly due to the fingering and water conning. Currently the field is producing around 8000 STB/Day with water cut around 80% and keeps increasing.
Schemes in enhancing and prolonging the already decline production and diminishing reserves strategically call for timely implementation of Enhanced Oil Recovery (EOR) process. Among various Enhanced Oil Recovery (EOR) process and techniques, Bamboo reservoirs appear especially amenable to thermal injection process. But Sudapet, ITB and PERTAMINA (an especial study) came up with different solution which is Huff and Buff of Chemical EOR, This proved to be one of the practical, promising and potential options in enhancing the recovery factor in Bamboo Field.
This paper will discuss the lab study scope, includes the core sample, fluid sample, phase behaviour test, spontaneous Imbibition Test, Compatibility test, Viscosity Mixture and core flood, well selection analysis as well as the implementation of SEMAR as pilot project in Bamboo Oil Field.
After implementation of the pilot as Huff and Puff in three wells the results show that about 18,000 STB of oil gained from adjacent wells, which indicate that SEMAR is very interesting to be evaluated for further steps in chemical EOR implementation for continuous Injection.
New Technique for Condensate Banking Removal in Gas Reservoirs
Authors: El Hajj Hicham , Shakeel Muzzammil 
Published: July 2016

Abstract
In unconventional and tight-gas reservoirs, hydraulic fracturing treatments are widely performed to recover significant amounts of hydrocarbon, thus establishing unconventional plays as commercially viable. However, in gas reservoirs, formation damage and various unfavorable conditions, such as condensate banking, phase trapping, water-blocking, etc., can cause production that is less than expected.
This paper introduces a new fracturing fluid additive that aims to help increase production following a hydraulic fracturing treatment and helps control fracture face damage. The new surfactant in the fracturing fluid system can allow faster production at higher rates. It can also provide a better regained permeability after hydraulic fracturing because it reduces formation damage caused by phase trapping and improves mobilization of liquid hydrocarbons, including condensate. The product has been typically designed for unconventional reservoirs, including tight gas, tight sandstone, shale, and coalbed methane.
Coreflooding experiments were conducted to demonstrate the performance and efficiency of this new additive in fracturing fluid and to optimize its concentration. Favorable results were obtained from the experiments that indicated good formation damage control in terms of regained permeability along with significant condensate production after the fracturing fluid treatment. The additive, when used in specific concentrations, has physical and chemical properties that contribute to improving hydrocarbon production by enhancing the mobilization of liquid hydrocarbons. It tends to reduce the capillary pressure and surface tension of the treating fluid to allow higher fluid mobility in the treated reservoir zone. This effective new fracturing fluid system is environmentally friendly and exhibits excellent performance under high-temperature/high-pressure conditions.
The fracturing fluid additive presented here helps overcome a condensate banking problem and unfavorable conditions, such as wells coming online slowly and low production rates resulting from formation damage following hydraulic fracturing treatments. Experiments validate the performance of the fracturing fluid additive, and significant condensate production for optimum additive concentration was observed during experimental treatments.